Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 60105 

mistakenly states that it was ‘‘Added by 

SB900–036.’’ Inspection holes at L167 and 

R167 were originally specified by SB600N– 

036. 

(c) Within 25 hours TIS, unless 

accomplished previously: 

(1) Thoroughly clean all attachment fittings 

and the surrounding areas, inspect the area 

for cracking, replace the upper right 

attachment fitting and all four nut plates, and 

paint the area inside of the attachment 

fittings in accordance with the 

Accomplishment Instructions, paragraph 

2.B., of MD Helicopters Service Bulletin 

SB600N–043, dated April 13, 2006 (SB600N– 

043). If a crack is found in any of the other 

three attachment fittings, before further 

flight, accomplish the actions described in 

paragraph (f) of this AD. 

(2) Using a 10x magnifying glass, inspect 

the attachment bolts’ threads and shanks for 

wear or damage in accordance with 

paragraph 2.B., of SB600N–043. If wear or 

damage is present, replace the attachment 

bolts with airworthy bolts. 

(d) Thereafter, at the specified intervals, 

remove the plug buttons from the inspection 

holes, and using a bright light, inspect the 

upper and lower left and upper and lower 

right attachment fittings, angles, and nut 

plates for a crack by following the 

Accomplishment Instruction paragraphs of 

SB600N–039, as follows, except you are not 

required to contact MDHI to meet the 

requirements of this AD. 

(1) At intervals not to exceed 25 hours TIS, 

through inspection holes at L167 and R167, 

inspect the upper left and upper right 

attachment fittings, angles, and nut plates by 

following the Accomplishment Instructions, 

paragraphs 2.B.(2) through 2.B.(4), of 

SB600N–039. 

(2) At intervals not to exceed 100 hours 

TIS, through inspection holes at L166 and 

R166, inspect the lower left and lower right 

attachment fittings, angles, and nut plates by 

following the Accomplishment Instructions, 

paragraphs 2.B.(2) through 2.B.(4), of 

SB600N–039. 

(e) If a crack is found in the upper right 

attachment fitting, or in any angle, nut plate, 

longeron, or if thread wear or damage is 

found on any nut plate or bolt, before further 

flight, replace the cracked or worn or 

damaged part with an appropriate airworthy 

part, or accomplish the actions in paragraph 

(f) of this AD. If cracking is found in any of 

the other three attachment fittings, before 

further flight, accomplish the actions 

described in paragraph (f) of this AD. 

(f) If required by paragraph (c)(1) of this 

AD, or if you make this modification to 

comply with paragraph (e) of this AD, modify 

the fuselage aft section to strengthen the 

tailboom attachments and the upper 

longerons by following paragraph 2, 

Accomplishment Instructions, of MDHI 

TB600N–007, dated January 12, 2004; 

TB600N–007, Revision 1, dated April 13, 

2006; or TB600N–007, Revision 2, dated 

October 5, 2006; except you are not required 

to contact the manufacturer. This 

modification to the fuselage aft section is 

terminating action for the requirements of 

this AD. 

(g) Within 24 months, modify the fuselage 

aft section to strengthen the tailboom 

attachments and upper longerons by 

following paragraph 2, Accomplishment 

Instructions, of MDHI TB600N–007, Revision 

2, dated October 5, 2006, except you are not 

required to contact the manufacturer. This 

modification to the fuselage aft section is 

terminating action for the requirements of 

this AD. 

(h) To request a different method of 

compliance or a different compliance time 

for this AD, follow the procedures in 14 CFR 

39.19. Contact the Manager, Los Angeles 

Aircraft Certification Office, Airframe 

Branch, FAA, ATTN: Eric Schrieber, 

Aviation Safety Engineer, 3960 Paramount 

Blvd., Lakewood, California 90712, telephone 

(562) 627–5348, fax (562) 627–5210, for 

information about previously approved 

alternative methods of compliance. 

(i) Inspect, replace, and modify the 

fuselage aft section according to the specified 

portions of the following MD Helicopters 

service information, as applicable. 

(1) Service Bulletin SB600N–036, dated 

November 2, 2001; incorporated by reference 

as of April 29, 2002 (67 FR 17934, April 12, 

2002). 

(2) Service Bulletin SB600N–039, dated 

December 9, 2003; Service SB600N–043, 

dated April 13, 2006; and Technical Bulletin 

TB600N–007, Revision 1, dated April 13, 

2006; incorporated by reference as of April 

27, 2006 (71 FR 24808, April 27, 2006). 

(3) Technical Bulletin TB600N–007, 

Revision 2, dated October 5, 2006; 

incorporated by reference as of April 16, 

2008 (73 FR 13096, March 12, 2008). 

(4) The incorporation by reference of these 

documents was approved previously by the 

Director of the Federal Register in accordance 

with 5 U.S.C. 552(a) and 1 CFR part 51. 

(5) Copies of this service information may 

be obtained from MD Helicopters Inc., Attn: 

Customer Support Division, 4555 E. 

McDowell Rd., Mail Stop M615, Mesa, 

Arizona 85215–9734, telephone 1–800–388– 

3378, fax 480–346–6813, or on the Internet at 

http://www.mdhelicopters.com. 

(6) Copies may be inspected at the FAA, 

Office of the Regional Counsel, Southwest 

Region, 2601 Meacham Blvd., Room 663, Fort 

Worth, Texas, or at the National Archives 

and Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, or go 

to: http://www.archives.gov/federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

(j) This amendment becomes effective 

on October 27, 2008. 

Issued in Fort Worth, Texas, on September 

25, 2008. 

Mark R. Schilling, 

Acting Manager, Rotorcraft Directorate, 

Aircraft Certification Service. 

[FR Doc. E8–23540 Filed 10–9–08; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 301 

[Docket Nos. EF08–2011–000 and RM08–20– 

000] 

Sales of Electric Power to the 

Bonneville Power Administration; 

Revisions to Average System Cost 

Methodology 

September 30, 2008. 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Interim rule. 

SUMMARY: The Bonneville Power 

Administration (Bonneville) has 

submitted for the Federal Energy 

Regulatory Commission (Commission)’s 

approval a new methodology for 

determining the average system cost 

(ASC) of a utility’s resources under the 

Pacific Northwest Electric Power 

Planning and Conservation Act 

(Northwest Power Act). Bonneville 

requested that the Commission revise its 

regulations to incorporate the new 

methodology and to make the revised 

regulations effective October 1, 2008. 

On an interim basis, the Commission is 

conditionally revising its regulations 

governing the ASC methodology used 

by Bonneville in its Residential 

Exchange Program. The Commission 

also is requesting comments on 

whether, on a final basis, the 

Commission should approve the new 

ASC methodology proposed by 

Bonneville. 

DATES: Effective date: This interim rule 

is effective October 10, 2008. 

Applicability date: The initial 

exchange period begins October 1, 2008 

Comment date: Comments on the 

interim rule are due November 10, 2008. 

ADDRESSES: You may submit comments 

on the interim rule, identified by Docket 

Nos. EF08–2011–000 and RM08–20– 

000, by one of the following methods: 

• Agency Web site: http:// 

www.ferc.gov. Follow instructions for 

submitting comments via the eFiling 

link found in the Comment Procedures 

Section of the preamble. 

• Mail: Commenters unable to file 

comments electronically must mail or 

hand deliver an original and 14 copies 

of their comments to the Federal Energy 

Regulatory Commission, Secretary of the 

Commission, 888 First Street, NE., 

Washington, DC 20426. Please refer to 

the Comment Procedures Section of the 

preamble for additional information on 

how to file paper comments. 


jlentini on PROD1PC65 with RULES
60106 Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 

1 16 U.S.C. 839(c). 

2 Id. 

3 16 U.S.C. 839c(c)(1). 

4 Id. This rate is generally a lower rate. 

5See CP Nat’l Corp. v. BPA, 928 F.2d 905, 907 

(9th Cir. 1991) (quoting Public Utility Commissioner 

of Oregon v. BPA, 583 F. Supp. 752, 754 (D. Or. 

1984)). 

6 16 U.S.C. 839c(c)(2). 

7 16 U.S.C. 839c(c)(7). 

8 16 U.S.C. 839c(c)(7)(A)–(C). 

9 Methodology for Sales of Electric Power to 

Bonneville Power Administration, Order No. 400, 

FERC Stats. & Regs. ¶ 30,601 at 31,161 (1984), reh’g 

denied, Order No. 400–A, FERC 30 FERC ¶ 61,108 

(1985). 

10 16 U.S.C. 824, 824d, 824e. 

11Order No. 400, FERC Stats. & Regs. ¶ 30,601 at 

31,161. 

12 18 CFR Part 301. 

13The July 2008 Filing was noticed in Docket No. 

EF08–2011–000 in the Federal Register, 72 FR 

32633 (2008), with protests and interventions due 

on or before August 13, 2008. Timely motions to 

intervene and comments were filed by Avista 

Corporation, PacifiCorp, Portland General Electric 

Company, Puget Sound Energy, Inc., Public Utility 

District No. 1 of Clark County, Washington, and the 

Public Utility District No. 1 of Grays Harbor County, 

Washington. The Public Power Council and the 

Public Utility District No. 1 of Snohomish County, 

Washington filed motions to intervene out of time. 

In addition, the Idaho Power Company filed 

comments and a partial protest. The Idaho Public 

Utilities Commission filed a notice of intervention 

and protest. Bonneville filed an answer to 

interested parties’ comments and protests. 

Additionally, Bonneville filed an errata correction 

to its initial filing on September 12, 2008. 

14See Portland General Elec. Co. v. BPA, 501 F.3d 

1009 (9th Cir. 2007); Golden NW Aluminum, Inc. 

v. Bonneville Power Admin., 501 F.3d 1037 (9th Cir. 

2007). 

FOR FURTHER INFORMATION CONTACT:

Peter Radway (Technical Information), 

Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Phone: 202– 

502–8782, e-mail: 

peter.radway@ferc.gov. 

Julia A. Lake (Legal Information), 

Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Phone: 202– 

502–8370, e-mail: julia.lake@ferc.gov. 

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Joseph T. Kelliher, 

Chairman; Suedeen G. Kelly, Marc Spitzer, 

Philip D. Moeller, and Jon Wellinghoff. 

1. The Bonneville Power 

Administration (Bonneville) has 

submitted for the Federal Energy 

Regulatory Commission (Commission)’s 

approval a new methodology for 

determining the average system cost 

(ASC) of a utility’s resources under 

section 5(c) of the Pacific Northwest 

Electric Power Planning and 

Conservation Act (Northwest Power 

Act).1 Bonneville requested that the 

Commission revise its regulations to 

incorporate the new methodology and to 

make the revised regulations effective 

October 1, 2008. On an interim basis, 

the Commission is conditionally 

revising its regulations governing the 

ASC methodology used by Bonneville in 

its Residential Exchange Program. The 

Commission also is requesting 

comments on whether, on a final basis, 

the Commission should approve the 

new ASC methodology proposed by 

Bonneville. 

Background 

2. Section 5(c) of the Northwest Power 

Act provides for a Residential Exchange 

Program, which broadly speaking is 

designed to make the benefit of 

Bonneville’s relatively low preference 

power rates available to residential 

customers of investor-owned utilities in 

the Pacific Northwest.2 Although the 

Residential Exchange Program is 

available to any Pacific Northwest 

utility, the primary beneficiaries of the 

exchange are investor-owned utilities. 

Under the Residential Exchange 

Program, a utility may sell power to 

Bonneville at the average system cost of 

that utility’s resources.3 Bonneville then 

sells the same amount of power back to 

the utility at Bonneville’s priority firm 

exchange rate.4 The power exchange is 

generally viewed as a paper 

transaction.5 In almost all instances, 

Bonneville makes a payment to the 

utility for the difference between the 

utility’s average system cost and 

Bonneville’s priority firm exchange rate, 

multiplied by the utility’s residential 

and small farm load. 

3. The Northwest Power Act does not 

define what constitutes the average 

system cost of a utility’s resources.6

Instead, the Act grants Bonneville’s 

Administrator the authority to establish 

a methodology for determining an 

exchanging utility’s average system cost 

through a stakeholder process in 

consultation with the Northwest Power 

Planning Council, Bonneville’s 

customers, and appropriate State 

regulatory bodies in the region.7 The 

Northwest Power Act directed the 

Administrator to exclude the following 

three types of costs from the average 

system cost: (1) The cost of additional 

resources in an amount sufficient to 

serve any new large single load of the 

utility; (2) the cost of additional 

resources in an amount sufficient to 

meet any additional load outside the 

region occurring after December 5, 1980; 

and (3) any costs of any generating 

facility which is terminated prior to 

initial operation.8 Outside these explicit 

exclusions, the Northwest Power Act is 

silent on the costs that may be included 

or excluded in the average system cost. 

Bonneville’s Administrator decides 

what costs should be considered when 

calculating the average system cost, and 

what process should be used to make 

that determination. 

4. The Commission’s role in this 

exchange program is two-fold. First, 

under section 5(c)(7) of the Act, while 

Bonneville develops a methodology for 

determining a utility’s ASC (after 

consulting with various affected 

groups), the Commission must ‘‘review 

and approve’’ the methodology. Neither 

the statute nor its legislative history 

explains the nature of this review, 

however.9

5. The Commission’s second role in 

the exchange program arises from its 

Federal Power Act (FPA) 10

responsibility to review the wholesale 

sales rates of individual investor-owned 

utilities; the Commission reviews the 

rates for such sales from the investorowned utilities to Bonneville based on 

the ASC methodology. The 

Commission’s existing rules (18 CFR 

35.30 and 35.31) provide that the 

Commission will approve under the 

FPA any sale to Bonneville that is based 

on correct application of an approved 

methodology.11

6. On July 14, 2008, Bonneville filed 

a revised ASC methodology to replace 

the current ASC methodology approved 

by the Commission on a final basis in 

1984, and codified in part 301 of the 

Commission’s regulations (July 2008 

Filing).12 In its July 2008 Filing (which 

was corrected on September 12, 2008),13

Bonneville states that this is the first 

revision to its ASC methodology in 24 

years, and reflects changes in the energy 

industry that have transpired during 

that time. 

7. Bonneville explains that the 

stakeholder process that resulted in this 

revised ASC methodology began in May 

of 2007, following two Ninth Circuit 

opinions that held that Bonneville 

exceeded its statutory authority when it 

entered into certain Residential 

Exchange Program Settlement 

Agreements, and remanded Bonneville’s 

WP–02 wholesale power rates for 

improperly allocating the costs of the 

Residential Exchange Program 

Settlement Agreements to its preference 

customers.14 Bonneville explains that it 

ceased making Residential Exchange 

Program payments following these 2007 

decisions. 

8. Bonneville states that, before it can 

provide Residential Exchange Program 

payments, it must re-establish the 

Residential Exchange Program. 

According to Bonneville, this requires 

the following: (1) Negotiation of 

Residential Purchase and Sale 


jlentini on PROD1PC65 with RULES
Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 60107 

15 16 U.S.C. 839e. 

16Order No. 400, FERC Stats. & Regs. ¶ 30,601 at 

31,162. 

17 Id. 

18Regulations Implementing the National 

Environmental Policy Act, Order No. 486, FERC 

Stats. & Regs. ¶ 30,783 (1987). 

19 18 CFR 380.4(a)(15). 

20 5 U.S.C. 601–12. 

Agreements; (2) establishment of a 

Priority Firm Exchange rate in a 

Northwest Power Act section 7(i) 15 rate 

adjustment proceeding; and (3) 

calculation of utilities’ respective 

average system costs under an ASC 

methodology. Bonneville notes that, in 

a separate Bonneville proceeding, it 

negotiated new Residential Purchase 

and Sale Agreements to be effective 

October 1, 2008. And, in another 

Bonneville proceeding, it developed a 

revised priority firm exchange rate that 

it will submit to the Commission in a 

separate docket for interim approval. 

Bonneville explains that it must ensure 

that an ASC methodology is in effect to 

determine exchanging utilities’ average 

system costs to implement the 

Residential Exchange Program on 

October 1, 2008. Bonneville, therefore, 

requests the Commission to grant 

interim approval of the revised ASC 

methodology no later than October 1, 

2008. 

9. In its July 2008 Filing, Bonneville 

explains that the revised ASC 

methodology retains characteristics of 

the current ASC methodology. 

Bonneville explains, further, that the 

key differences are in how average 

system costs are calculated as well as 

the substance of the costs included and 

excluded from the average system cost 

calculation. Bonneville states that the 

revised ASC methodology adopts a 

streamlined approach to the average 

system cost calculations by using a 

different source of average system cost 

data, i.e., FERC Form No. 1 data, instead 

of state retail rate orders. Bonneville 

notes that, in addition, it proposes to 

adjust the average system costs less 

frequently. Bonneville asserts that the 

revised ASC methodology allows each 

utility to file a single, combined average 

system cost for its entire within-region 

service territory as opposed to an 

average system cost for each state 

jurisdiction in which it operates. 

10. Bonneville also explains that it is 

proposing to establish a two-year 

average system cost that will correspond 

with its two-year wholesale power rate 

periods. Bonneville explains, further, 

that utilities’ average system costs will 

stay fixed except for pre-determined 

adjustments to reflect the costs of new 

resources incurred during the rate/ 

exchange period. According to 

Bonneville, these features will lessen 

the number of average system costs 

filings reviewed by Bonneville and the 

Commission. 

11. Bonneville explains that the 

revised ASC methodology also changes 

the average system cost treatment of 

certain costs. Bonneville states that it is 

allowing utilities to exchange a full 

return on equity (instead of the 

weighted cost of debt); the utility’s 

marginal Federal income tax; and the 

utility’s transmission plant costs. 

12. Bonneville requests Commission 

approval of this new ASC methodology. 

Discussion 

13. For the reasons discussed below, 

the Commission has determined to 

conditionally grant interim approval of 

Bonneville’s new ASC methodology. We 

note, however, that the methodology 

must be further reviewed before final 

approval can be given; this review 

cannot be completed during the short 

time period in which the methodology 

has been before the Commission. 

14. Interim approval is necessary to 

further the intent of the Northwest 

Power Act. An approved (by the 

Commission) ASC methodology is 

fundamental to the Residential 

Exchange Program found in section 5 of 

the Northwest Power Act. The 

methodology defines the rates at which 

sales will be made to Bonneville which, 

when made, will permit exchanges to 

occur. 

15. This warrants approval on an 

interim basis of Bonneville’s revised 

ASC methodology. However, the 

Commission is obligated to review and 

approve the methodology in accordance 

with certain procedures and its 

responsibilities to protect the public 

interest, and the Commission has yet to 

finish its review of the proposed 

methodology. For these reasons, the 

approval granted here is interim only. 

16. Moreover, such interim approval 

must be conditioned to ensure that the 

public interest is protected during the 

time period the interim approval is in 

place. The revised ASC methodology 

will affect rates paid by, and to, 

Bonneville. To the extent that the ASC 

methodology finally approved by the 

Commission differs from that filed by 

Bonneville in its July 2008 filing, and 

which is approved on an interim basis 

here, the rates paid may be different 

from the rate under the ASC 

methodology finally approved by the 

Commission. The Commission must be 

assured that any such difference can be 

corrected, through refund or surcharge, 

to the extent of the difference, should 

that be appropriate. To ensure this 

result, the Commission grants interim 

approval only conditionally and subject 

to refund or surcharge.16

17. The Commission attaches this 

condition with the full awareness that, 

by so doing, some uncertainty is 

injected into the exchange process. 

Rates paid may be too high or too low, 

depending upon the ASC methodology 

finally approved by the Commission. 

However, under the circumstances, 

some uncertainty is unavoidable. The 

Commission staff has completed a 

preliminary review of the methodology, 

however, and is satisfied that such 

uncertainty is minimal. Moreover the 

methodology is a product not only of a 

stakeholder process, which should serve 

to minimize any uncertainty, but also of 

notice and comment procedures. This 

provides good grounds for finding that, 

for purposes of interim approval, due 

process has been observed.17

Paperwork Reduction Act Statement 

18. A Paperwork Reduction Act 

Statement is not required for this 

interim rule because the regulations 

adopt a methodology used by a federal 

power marketing administration, in this 

case Bonneville. 

Environmental Analysis 

19. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.18 The Commission has 

categorically excluded certain actions 

from this requirement as not having a 

significant effect on the human 

environment. Included in these 

exclusions are Commission actions 

addressing proposed public utility rates 

and Commission confirmation, 

approval, and disapproval of rate filings 

submitted by federal power marketing 

administrations under the Northwest 

Power Act.19 The actions herein fall 

within this categorical exclusion in the 

Commission’s regulations. 

Regulatory Flexibility Act 

20. The Regulatory Flexibility Act of 

1980 (RFA) 20 generally requires a 

description and analysis of the effect 

that an interim rule will have on small 

entities or a certification that the rule 

will not have a significant economic 

impact on a substantial number of small 

entities. 

21. The Commission concludes that 

this interim rule will not have such an 

impact on a substantial number of small 

entities. Bonneville is a federal power 

marketing administration. And the 

investor-owned utilities which are 


jlentini on PROD1PC65 with RULES
60108 Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 

21 5 U.S.C. 602(3) citing section 3 of the Small 

Business Act, 15 U.S.C. 632. Section 3 of the Small 

Business Act defines ‘‘small business concern’’ as 

a business which is independently owned and 

operated, and which is not dominant in its field of 

operation. 

22All motions to intervene, comments, protests, 

and all notices of intervention filed in Docket No. 

EF08–2011–000; will be considered to have been 

filed in Docket No. RM08–20–000. All comments 

and protests filed in Docket No. EF08–2011–000 

will be addressed in the final rule issued in Docket 

No. RM08–20–000. Inventernors in Docket No. 

EF08–2011–000 wising to file additional 

commments may do so. 23 5 U.S.C. 553(d)93. 

participating in the Residential 

Exchange Program are not small 

entities.21 Moreover, the number of 

utilities participating in the program is 

not substantial; only nine utilities 

whose rates are within the 

Commission’s jurisdiction are 

participating in the program. 

22. For these reasons, the Commission 

certifies under the RFA that this interim 

rule will not have a significant 

economic effect on a substantial number 

of small entities. 

Comment Procedures 

23. The Commission invites interested 

persons to submit comments on the 

matters and issues raised by the 

proposed revised ASC methodology. 

Comments are due November 10, 

2008.22 Comments must refer to Docket 

Nos. EF08–2011–000 and RM08–20– 

000, and must include the commenter’s 

name, the organization they represent, if 

applicable, and their address in their 

comments. 

24. The Commission encourages 

comments to be filed electronically via 

the eFiling link on the Commission’s 

Web site at http://www.ferc.gov. The 

Commission accepts most standard 

word processing formats. Documents 

created electronically using word 

processing software should be filed in 

native applications or print-to-PDF 

format and not in a scanned format. 

Commenters filing electronically do not 

need to make a paper filing. 

25. Commenters that are not able to 

file comments electronically must send 

an original and 14 copies of their 

comments to the Federal Energy 

Regulatory Commission, Secretary of the 

Commission, 888 First Street, NE., 

Washington, DC 40246. 

26. All comments will be placed in 

the Commission’s public files and may 

be viewed, printed, or downloaded 

remotely as described in the Document 

Availability section below. Commenters 

on this proposal are not required to 

serve copies of their comments on other 

commenters. 

Document Availability 

27. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through the 

Commission’s home page http:// 

www.ferc.gov and in the Commission’s 

Public Reference Room during normal 

business hours (8:30 a.m. to 5 p.m. 

Eastern time) at 888 First Street, NE., 

Room 2A, Washington, DC 20426. 

28. From the Commission’s home 

page on the Internet, this information is 

available on eLibrary. The full text of 

this document is available on eLibrary 

in PDF and Microsoft Word format for 

viewing, printing, and/or downloading. 

To access this document in eLibrary, 

type the document number excluding 

the last three digits of this document in 

the docket number field. 

29. User assistance is available for 

eLibrary and the Commission’s Web site 

during normal business hours from 

FERC Online Support at (202) 502–6652 

(toll free at 1–866–208–3676) or e-mail 

at ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

Effective Date 

30. For the reasons discussed above, 

the Commission finds good cause under 

section 553(d)(3) of the Administrative 

Procedure Act 23 to make this rule 

effective immediately, rather than 30 

days after publication in the Federal 

Register. The long-term impact of 

delaying early implementation of a new 

revised ASC methodology justifies its 

immediate effectiveness. This interim 

rule, therefore, will take effect on 

October 1, 2008. 

List of Subjects in 18 CFR Part 301 

Electric power rates; Electric utilities; 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

■ In consideration of the foregoing, the 

Commission amends Title 18, Chapter I 

of the Code of Federal Regulations, by 

revising Part 301 to read as follows: 

PART 301—AVERAGE SYSTEM COST 

METHODOLOGY FOR SALES FROM 

UTILITIES TO BONNEVILLE POWER 

ADMINISTRATION UNDER 

NORTHWEST POWER ACT 

Sec. 

301.1 Applicability. 

301.2 Definitions. 

301.3 Filing procedures. 

301.4 Bonneville Power Administration’s 

Average System Cost review process. 

301.5 Exchange Period Average System 

Cost determination. 

301.6 Change in Average System Cost 

methodology. 

301.7 Sample time line review procedures. 

301.8 Appendix 1 instructions. 

301.9 Functionalization of Average System 

Cost methodology. 

Table 1 to Part 301—Functionalization and 

Escalation Codes. 

Appendix 1 to Part 301—Bonneville Power 

Administration Residential Purchase and 

Sales Agreement 

Appendix 2 to Part 301—Chief Financial 

Officer Attestation 

Authority: 16 U.S.C. 839–839h. 

§ 301.1 Applicability. 

The regulations in this part provide 

the procedures by which regional 

utilities will submit Average System 

Cost (ASC) filings to the Bonneville 

Power Administration (Bonneville), and 

by which Bonneville will review those 

filings. Bonneville’s review will 

determine a utility’s ASC for the 

purpose of participating in the 

Residential Exchange Program under 

section 5(c) of the Pacific Northwest 

Electric Power Planning and 

Conservation Act (Northwest Power 

Act). 16 U.S.C. 839c(c). 

§ 301.2 Definitions. 

For purposes of this section, the 

following definitions apply: 

Appendix 1. Appendix 1 is the 

electronic form on which a utility 

reports its Contract System Costs and 

other necessary data to Bonneville for 

the calculation of the utility’s Base 

Period. 

Average System Cost (ASC). The rate 

charged by a utility to Bonneville for the 

agency’s purchase of power from the 

utility under section 5(c) of the 

Northwest Power Act for each Exchange 

Period, and is the quotient obtained by 

dividing the Contract System Costs by 

Contract System Load. 

Base Period. The calendar year of the 

most recent Form 1 data. 

Base Period ASC. The ASC 

determined in the Review Period using 

the utility’s Base Period data. 

Contract High Water Mark (CHWM). 

The average MW amount used to define 

access to Tier 1-priced power. CHWM is 

equal to the adjusted historical load for 

each customer proportionately scaled to 

Tier 1 System Resources and adjusted 

for conservation achieved. The CHWM 

is specified in each eligible customer’s 

Contract High Water Mark Contract. 


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Commission. The Federal Energy 

Regulatory Commission. 

Contract System Costs. The utility’s 

costs for production and transmission 

resources, including power purchases 

and conservation measures, which costs 

are includable in, and subject to, the 

provisions of Appendix 1. Under no 

circumstances will Contract System 

Costs include costs excluded from ASC 

by section 5(c)(7) of the Northwest 

Power Act. 

Contract System Load. The total 

regional retail load included in Form 1, 

or for a consumer-owned utility 

(preference customers), the total retail 

load from the most recent annual 

audited financial statement as adjusted 

pursuant to the ASC methodology. 

Exchange Period. The period during 

which a utility’s Bonneville-approved 

ASC is effective for the calculation of 

the utility’s Residential Exchange 

Program benefits. The initial Exchange 

Period under this ASC methodology is 

from October 1, 2007, through 

September 30, 2009. Subsequent 

Exchange Periods will be the period of 

time concurrent with the Bonneville 

rate period beginning October 1, or the 

effective date of Bonneville’s rate 

period. 

Exchange Period ASC. The Base 

Period ASC escalated to a year(s) 

consistent with the Exchange Period. 

Form 1. The annual filing submitted 

to the Federal Energy Regulatory 

Commission required by 18 CFR § 141.1. 

Jurisdiction. The service territory of 

the utility within which a particular 

regulatory body has authority to 

approve a utility’s retail rates. 

Jurisdictions must be within the Pacific 

Northwest region as defined in the 

Northwest Power Act. 

Labor Ratios. The ratios which assign 

costs on a pro rata basis using salary 

and wage data for Production, 

Transmission, and Distribution/Other 

functions included in the utility’s most 

recently filed Form 1. For consumerowned utilities, comparable data will be 

used based on the cost-of-service study 

used as the basis for retail rates at the 

time of review. 

New Large Single Load. That load 

defined in section 3(13) of the 

Northwest Power Act, and determined 

by Bonneville as specified in power 

sales contracts and Residential Sale and 

Purchase Agreements (RPSA) with its 

Regional Power Sales Customers. 

Public Purpose Charge. Any charge 

based on a utility’s total retail sales in 

a jurisdiction that is given to 

independent nonprofit entities or 

agencies of state and local governments 

for the purpose of funding within the 

utility’s service territory including: 

(1) Conservation programs in lieu of 

utility conservation programs; and 

(2) Acquisition of renewable 

resources. 

Rate Period High Water Mark 

(RHWM). The amount used to define 

each customer’s eligibility to purchase 

power at a Tier 1 price for the relevant 

Rate Period, subject to the customer’s 

New Requirement, expressed in average 

megawatts (aMW). RHWM is equal to 

the customer’s CHWM as adjusted for 

changes in Tier 1 System Resources. 

The RHWM is determined for each 

eligible customer in the RHWM Process 

preceding each rate case. 

Regional Power Sales Customer. Any 

entity that can contract directly with 

Bonneville for the purchase of power 

under sections 5(b), 5(c), or 5(d) of the 

Northwest Power Act for delivery in the 

region as defined by section 3(14) of the 

Northwest Power Act. 

Regulatory Body. A state Commission 

or consumer-owned utility governing 

body, or other entity authorized to 

establish retail electric rates in a 

Jurisdiction. 

Residential Purchase and Sale 

Agreement (RPSA). The power sales 

contract under section 5(c) of the 

Northwest Power Act between 

Bonneville and the utility that defines 

and implements the power purchase 

and sale. 

Review Period. The period of time 

during which a utility’s Appendix 1 is 

under review by Bonneville. The 

Review Period begins on June 1, and 

ends on or about November 15 of the 

fiscal year prior to the fiscal year 

Bonneville implements a change in 

wholesale power rates. 

Utility. An investor-owned or 

consumer-owned (preference) Regional 

Power Sales Customer that has executed 

a Residential Purchase and Sale 

Agreement. 

§ 301.3 Filing procedures. 

The following procedures provide the 

filing requirements for all utilities that 

file an Appendix 1 to participate in the 

Residential Exchange Program. Utilities 

must file an Appendix 1 with 

Bonneville to permit the calculation of 

each utility’s ASC. 

(a) Initial Exchange Period (2009). 

(1) A utility’s ASC for fiscal year FY 

2009 will be determined by Bonneville 

in accordance with this ASC 

methodology, and will constitute the 

effective ASC for the Residential 

Exchange Program effective October 1, 

2008, unless: 

(i) The Commission fails to approve 

the methodology; 

(ii) The Commission amends the 

methodology in a manner that changes 

the utility’s ASC established by 

Bonneville; or 

(iii) The methodology is legally 

challenged, and not affirmed on appeal 

by the United States Court of Appeals 

for the Ninth Circuit. 

(iv) The Base Period Appendix 1 

filing will be from CY 2006. The Initial 

Exchange Period will begin October 1, 

2008 provided that the Commission 

grants the methodology interim or final 

approval by that date. The Initial 

Exchange Period will end on September 

30, 2009. 

(2) Since the Initial Exchange Period 

begins on October 1, 2008, and the 

utility filings for FY 2008 are due that 

same day, Bonneville will pay the 

exchanging utilities based on their 

October 1, 2008 filed ASC, and calculate 

a true-up to the final ASC after the 

Bonneville Review Period is concluded, 

and Bonneville issues the final ASC 

reports. If a utility fails to file an 

Appendix 1 by October 1, 2008, 

Bonneville will follow the procedures 

outlined in paragraphs (d) and (e) of this 

section. Prior to the commencement of 

the Bonneville review process, 

Bonneville will publish a schedule for 

the review of the filings. Bonneville may 

issue a schedule different from the 

prescribed schedule in order to ensure 

that ASCs are established in time to be 

trued-up during FY 2009. 

(b) Second Exchange Period (FY 

2010–2011). 

(1) For the Second Exchange Period, 

utilities are required to submit their 

ASC filings by October 1, 2008 for FY 

2010–2011. If a utility fails to file an 

Appendix 1 by October 1, 2008, 

Bonneville will follow the procedures 

outlined in paragraphs (d) and (e) of this 

section. Prior to the commencement of 

the Bonneville Review Period, 

Bonneville will publish a schedule for 

review of the filings. Bonneville may 

issue a schedule different from the 

prescribed schedule in order to ensure 

that ASCs are established in time to be 

incorporated in Bonneville’s FY 2010– 

2011 wholesale power rate case. 

(2) After Bonneville’s review process 

is concluded, Bonneville will issue 

utility ASC Reports to reflect the final 

ASCs for the FY 2010–2011 rate period. 

(c) Subsequent Exchange Periods. 

(1) Subsequent Exchange Periods will 

be equal to the term of subsequent 

Bonneville wholesale power rate 

periods. ASCs will change during the 

Exchange Periods only for the reasons 

provided in paragraph (a)(1) of this 

section. 

(2) Except as provided for in the 

Initial and Second Exchange Periods, 

utilities must file electronically at least 

one Appendix 1 with Bonneville by 


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60110 Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 

June 1 of each year. In years when 

Bonneville is not conducting a review 

process, these filings will be for 

informational purposes only, and will 

not change a utility’s ASC. The 

Appendix 1 must be accompanied by 

supporting documentation, studies and 

analyses used to prepare the Appendix 

1. 

(i) For investor-owned utilities, 

Appendix 1 must be based on the 

utility’s most recently filed Form 1 and 

limited information from prior Form 1 

filings as required. 

(ii) For consumer-owned utilities, 

Appendix 1 must be based on the 

utility’s most recent audited financial 

information, and must be accompanied 

by a cost-of-service analysis. 

(iii) Each Appendix 1 must contain an 

attestation signed by a senior officer of 

the utility stating that the filing has been 

compiled in accordance with the 

Commission’s Uniform System of 

Accounts, the ASC methodology in part 

301 of the Commission’s regulations, 

and Generally Accepted Accounting 

Principles, and is consistent with 

applicable orders and policies of the 

utility’s Regulatory Body. 

(d) Failure to file an Appendix 1. If a 

utility fails to timely file an Appendix 

1, and refuses to cure the problem 

within the period to cure provided in 

paragraph (f) of this section, Bonneville 

will make the utility’s Appendix 1 

filing. The utility will waive its right to 

participate in the ASC review 

proceeding to establish its ASC. All 

other parties will be permitted to 

participate, and present arguments 

challenging the utility’s ASC. 

(e) Filing a patently deficient 

Appendix 1. If a utility files its initial 

Appendix 1, and it is patently deficient 

as determined by Bonneville, and the 

period to cure, as outlined in paragraph 

(f) of this section, has expired, 

Bonneville will make the utility’s 

Appendix 1 filing. The utility will 

waive its right to participate in the ASC 

review proceeding to establish its ASC. 

A utility filing a patently deficient ASC 

filing must allow Bonneville the 

discretion to set its ASC for the 

Exchange Period, and Bonneville will 

not be required to include any proposed 

adjustments for resource changes or 

changes in service territories in the 

Appendix 1 filing. 

(f) Period to cure. If a utility fails to 

timely file an Appendix 1, or if it files 

an ASC that Bonneville determines is 

patently deficient, Bonneville will 

provide the utility with written notice 

and a period of seven (7) calendar days 

within which to file or to re-file a new 

or corrected Appendix 1. In the event 

the utility fails to file or re-file by the 

end of the seven-day cure period, or if 

the re-filed Appendix 1 is determined 

patently deficient, Bonneville will make 

the utility’s Appendix 1 filing. The 

utility will waive its right to participate 

in the ASC review proceeding to 

establish its ASC. All other parties will 

be permitted to participate and present 

arguments challenging the utility’s ASC. 

A utility filing a patently deficient ASC 

filing will allow Bonneville discretion 

to set its ASC for the Exchange Period, 

and Bonneville will not be required to 

include any proposed adjustments for 

resources changes or changes in service 

territories in the Appendix 1 filing. 

(g) Failure to file an Appendix 1 

because of a new Residential Purchase 

and Sale Agreement. After the Initial 

and Second Exchange Periods, if a 

utility fails to file its Appendix 1 by 

June 1 because it executed a Residential 

Purchase and Sale Agreement after 

commencement of a Review Period or 

during the subsequent Exchange Period, 

Bonneville may set the utility’s ASC 

equal to the Priority Firm Exchange rate 

until the end of the Exchange Period. 

(h) Notice of filing of Appendix 1. (1) 

After a utility files an Appendix 1 

electronically, Bonneville will post the 

filings and non-confidential 

documentation on its electronic Web 

site. Access to the information will be 

subject to any confidentiality rules or 

requirements established by Bonneville. 

(2) Bonneville will advise parties of 

the right to file a petition to intervene 

in Bonneville’s ASC review process. 

§ 301.4 Bonneville Power Administration’s 

Average System Cost Review Process. 

During a Review Period, the following 

procedures apply. These procedures 

will not apply to informational ASC 

filings made outside of a Review Period. 

(a) Bonneville may petition to 

intervene in each retail rate proceeding 

for each utility participating in the 

Residential Exchange Program. If 

Bonneville or any of its Regional Power 

Sales Customers is denied the right to 

intervene in a retail rate review 

proceeding of a filing utility when the 

intervention is for purposes of obtaining 

any information regarding costs or facts 

relevant to the determination of a 

utility’s ASC (after making a good faith 

effort to intervene in the retail rate 

proceeding and timely complying with 

applicable procedures to intervene in 

the retail rate proceeding), Bonneville 

may set that utility’s ASC equal to the 

Priority Firm Exchange Rate for the 

following Exchange Period. Exchanging 

utilities must provide Bonneville and 

Regional Power Sales Customers with at 

least 60 days notice of their intent to 

change their retail rates. 

(b) Each Appendix 1 will be reviewed 

by Bonneville or its designee and 

subject to a public process to determine 

whether the Contract System Costs are 

consistent with Generally Accepted 

Accounting Principles for electric 

utilities, whether Contract System Costs 

contain only allowed costs, and whether 

the revised Appendix 1 complies with 

the requirements of the ASC 

methodology, including applicable 

definitions and requirements 

incorporated from the Commission’s 

Uniform System of Accounts. In 

addition, each Appendix 1 will be 

reviewed by Bonneville or its designee 

to determine whether the Contract 

System Load used by the utility is an 

appropriate load for purposes of the 

utility’s ASC computation. 

(c)(1) In calculating ASCs, Bonneville 

will make an independent 

determination of the following: 

(i) The appropriateness of the 

inclusion of costs; 

(ii) The reasonableness of the costs 

included in Contract System Costs; and 

(iii) The appropriateness of Contract 

System Loads. 

(2) Bonneville will not be obligated to 

pay an ASC different than the ASC 

based on Contract System Costs and 

Contract System Load as determined by 

Bonneville. 

(3) If a final order of the Commission 

or a reviewing court rejects Bonneville’s 

ASC determination, the ASC payable by 

Bonneville will be the ASC as revised 

by Bonneville on remand. 

(d) The Appendix 1 filing will be 

subject to review as follows: 

(1) The Bonneville review process 

(not including the Initial and Second 

Exchange Periods) commences June 1 

(Day 1) of the Review Period (or other 

date as may be established by 

Bonneville). Bonneville will review all 

utilities’ ASCs concurrently in a public 

process. 

(2) The dates identified in these 

regulations and those listed on the 

sample time line shown in § 301.7 are 

generic, and intended to illustrate a time 

line that is representative of the ASC 

review process. Unless specified, the 

days represent calendar days. Each 

spring, prior to the Review Period, 

Bonneville will post on its ASC 

methodology Web site (http:// 

www.bpa.gov/corporte/finance/ascm) or 

its successor, a detailed schedule, 

accommodating the applicable holidays 

and weekends, that will be the official 

schedule for that Review Period. 

(e) Review Period time line. 

(1) Day 1. Utility filings due to 

Bonneville. 

(2) Day 3. Bonneville posts the utility 

filings to its electronic Web site. 


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Access to the information will be 

subject to any confidentiality rules or 

requirements established by Bonneville. 

(3) Day 7. Deadline to file utilityspecific petitions to intervene with 

Bonneville for the review process. Any 

Regional Power Sales Customer or state 

utility Regulatory Body who so requests 

will be accorded party status for 

Bonneville’s ASC review process if the 

request is received by the established 

deadline. Other interested parties also 

may submit a petition to intervene, and 

Bonneville will grant party status at its 

discretion. Petitions to intervene must 

state with particularity the petitioner’s 

interest in the ASC review proceeding. 

Petitions to intervene must be filed for 

each respective Bonneville review 

proceeding in order for a party to 

comment on the individual proceedings. 

The filing utility is automatically a party 

to its own ASC review proceeding. 

Bonneville will grant or deny petitions 

to intervene within seven (7) days after 

the deadline for filing the petitions. 

(4) Day 10. Bonneville grants or 

denies petitions to intervene. 

(5) Day 11–66. Parties allowed to 

submit data requests. Bonneville and 

parties will file data requests 

electronically with the utility and 

Bonneville. Bonneville will make data 

requests available to all parties. Each 

utility will respond to requests for 

information relevant to the utility’s 

Appendix 1 filing, provided that the 

furnishing of proprietary or confidential 

information to any party may be made 

contingent on the granting of proper 

safeguards to prevent unauthorized use 

or disclosure. The responses must be 

sent to the requester and Bonneville. For 

each data request, the responding utility 

has seven (7) days to provide the 

requested data or object. If a utility files 

an objection to a data request, the party 

submitting the data request has four (4) 

days to respond to the objection. After 

the response to the objection is received, 

or the four (4) days to respond has 

elapsed, Bonneville then has seven (7) 

days to issue a ruling as to whether the 

utility’s objection will be sustained or 

overruled. If the objection is overruled, 

the utility must provide the data 

requested within seven (7) days after the 

ruling. If a utility does not provide the 

requested data, Bonneville may, in its 

discretion, remove from Contract 

System Costs all costs associated with 

the data not provided. 

(6) Day TBD. Bonneville will begin 

workshops on all Appendix 1 filings 

based on the specific schedules. 

Utilities filing an Appendix 1 will have 

staff or agents available for questioning 

by Bonneville and other parties to the 

proceeding. The primary purpose of the 

first workshop is to clarify data, work 

papers, supporting documentation and 

assumptions used to prepare the 

Appendix 1. 

(7) Day 88. By this day, Bonneville 

and parties may file electronically with 

Bonneville an issue list identifying 

contested elements of a utility’s ASC 

filing and the basis for the parties’ 

issues. Bonneville will make the issue 

lists available to all parties. 

(8) Day 102. By this day, each filing 

utility will electronically file a response 

to the issue lists. Bonneville and other 

parties also may file comments in 

response to the issue lists. 

(9) Day 108. By this day, a workshop 

will be held to discuss and resolve the 

issues raised by parties through their 

issue lists. 

(10) Day 111. Requests for oral 

argument before the Administrator or 

his/her designee must be submitted in 

writing to Bonneville by this day. The 

requests must contain a statement 

providing reasons why the party 

believes oral argument is necessary. 

(11) Day 114. By this day, Bonneville, 

at its discretion, may grant or deny any 

request for oral argument. 

(12) Day 123. In the event a request 

for oral argument is granted, the 

requesting party will present its 

arguments first. Responding parties will 

present their arguments following the 

requesting party’s arguments. The 

Administrator or his/her designee, at his 

discretion, may provide an opportunity 

for the requesting party to reply. Oral 

arguments will be presented no later 

than this day. 

(13) Day 141. By this day, Bonneville 

will publish for comment, and serve 

electronically draft utility ASC reports 

on all parties. The reports will contain 

analyses and decisions on all contested 

issues raised in the ASC review process. 

(14) Day 154. By this day, the utility 

and parties may file comments on the 

draft utility ASC reports. 

(15) Day 167. The Bonneville 

Administrator will issue final utility 

ASC reports. 

(16) If Bonneville has not issued the 

final utility ASC reports by the end of 

the Review Period, the ASC filed by the 

utility will be the Exchange Period ASC 

until the date Bonneville issues the final 

utility ASC reports. The final ASCs 

determined by Bonneville will then be 

the Exchange Period ASCs effective 

back to the beginning of the Exchange 

Period and until the end of the 

Exchange Period. 

§ 301.5 Exchange Period Average System 

Cost Determination. 

(a) Escalation to Exchange Period. 

(1) Bonneville will escalate 

Bonneville-approved Base Period costs 

to the midpoint of the fiscal year for a 

one-year rate period/Exchange Period, 

and to the midpoint of the two-year 

period for a two-year rate period/ 

Exchange Period to calculate Exchange 

Period ASCs. 

(2) For purposes of the escalation 

referenced in paragraph (a)(1) of this 

section, Bonneville will use Global 

Insight’s (or its successor) forecast of 

cost increases for capital costs and fuel 

(except natural gas), Operations & 

Maintenance and General & 

Administrative expenses; and 

Bonneville’s forecast of market prices 

for investor-owned utility purchases to 

meet load growth and to estimate shortterm and non-firm power purchase costs 

and sales revenues; and Bonneville’s 

forecast of natural gas prices and 

Bonneville’s estimates of the rates it will 

charge for its Priority Firm and other 

products. 

(3) With the exception of the natural 

gas escalator provided by Bonneville, 

the following list of acronyms defines 

Global Insight’s escalation codes. These 

escalators will be used for each line 

item included in Appendix 1. 

(i) A&G—Administrative and General. 

(ii) CACNT—Customer Account. 

(iii) CD—Construction, Distribution 

Plant. 

(iv) CONSTANT—Constant. 

(v) CSALES—Customer Sales. 

(vi) CSERVE—Customer Service. 

(vii) COAL—Coal. 

(viii) DMN—Distribution Maintenance. 

(ix) HMN—Hydro Maintenance. 

(x) HOPS—Hydro Operations. 

(xi) INF—Inflation. 

(xii) NATGAS—Natural Gas. 

(xiii) NFUEL—Nuclear Fuel. 

(xiv) NMN—Nuclear Maintenance. 

(xv) NOPS—Nuclear Operations. 

(xvi) OMN—Other Production 

Maintenance. 

(xvii) OOPS—Other Production 

Operations. 

(xviii) SMN—Steam Maintenance. 

(xix) SOPS—Steam Operations. 

(xx) TMN—Transmission Maintenance. 

(xxi) TOPS—Transmission Operations. 

(xxii) WAGES—Wages. 

(4) If any of the escalators specified in 

the ASC methodology are no longer 

available, Bonneville will designate a 

replacement source of escalators that, as 

near as possible, replicates the results 

produced by the prior escalator, and, if 

a replacement source is not available, 

the replacement escalator will be the 

forecast of the GDP Price Deflator. 

(5) Bonneville will base the costs of 

power products purchased from 

Bonneville on Bonneville’s forecast of 

prices for its products. 

(b) Treatment of sales for resale and 

power purchases. 


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60112 Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations 

(1) Bonneville will escalate long-term 

and intermediate term (as defined by the 

Commission) firm purchased power 

costs and sales for resale revenues at the 

rate of inflation. 

(2) Bonneville will not normalize 

short-term purchases and sales for 

resale. The short-term purchases and 

sales for resale for the Base Period will 

be used as the starting values. A utility 

will be allowed to include new plant 

additions, and use a utility-specific 

forecast for the price of purchased 

power and sales for resale price to value 

purchased power expenses and sales for 

resale revenue to be included in the 

Exchange Period ASC. 

(3) Bonneville will use the following 

method to determine separate market 

prices to forecast short-term purchased 

power expense and sales for resale 

revenues to calculate Exchange Period 

ASCs: 

(i) The utility’s average short-term 

purchased power price and short-term 

sales for resale price will be calculated 

for each year for the most recent three 

years of actual data (Base Period and 

prior two years). 

(ii) The midpoint between the utility’s 

average short-term sales for resale price 

will be calculated for each of the years 

in paragraph (b)(3)(i) of this section. 

(iii) The percentage spread around the 

utility’s midpoint between the average 

short-term purchased power price and 

short-term sales for resale price will be 

escalated for each of the years identified 

in paragraph (b)(3)(i) of this section. 

(iv) A weighted average spread for the 

utility’s most recent three years of actual 

data (Base Period and prior two years) 

will be calculated. The following 

weighting scale will be used: 

(A) Three (3) times Base Period 

spread. 

(B) Two times (Base Period minus 1) 

spread. 

(C) One time (Base Period minus 2) 

spread. 

(v) The Base Period midpoint price 

calculated in paragraph (b)(3)(ii) of this 

section will be applied to the forecasted 

midpoint calculated in paragraph 

(b)(3)(iv) of this section to determine the 

purchased power and sales for resale 

price, to value purchased power 

expenses and sales for revenue to be 

included in the Exchange Period ASC. 

(vi) The weighted average spread 

calculated in paragraph (b)(3)(iv) of this 

section to determine the purchased 

power and sales for resale price, to 

value purchased power expenses and 

sales for resale revenue to be included 

in the Exchange Period ASC. 

(vii) This same method will be used 

to calculate the market price forecast for 

short-term, purchased power expense 

and sales for resale revenues for use in 

the load growth not met by new 

resource additions. 

(c) Major resource additions and 

materiality thresholds. 

(1) During the Exchange Period, 

Bonneville will allow changes to a 

utility’s ASC to account for major new 

purchased power contracts or major 

new resource additions that come online, and are used to meet the utility’s 

retail load. These changes, however, 

have to meet a materiality threshold in 

order for Bonneville to allow an ASC to 

change. These ASCs will be determined 

by Bonneville during the Review Period. 

The changes to the ASC will become 

effective when the resource begins 

commercial operation, or power is 

received under the purchased power 

contract. The criteria also will apply to 

resources that are sold, transferred, or 

retired. 

(2) Bonneville will use the following 

method to determine the changes in 

ASC due to major new resource 

additions or reductions, subject to 

meeting the materiality threshold. These 

additions will include new production 

resource investments, new generating 

resource investments, new transmission 

investments, long-term generating 

contracts, pollution control and 

environmental compliance investments 

relating to generating resources, 

transmission resources or contracts, 

hydro relicensing costs and fees, and 

plant rehabilitation investments. 

(3) Bonneville will apply a materiality 

threshold of 2.5 percent change in a 

utility’s Base Period ASC to determine 

when a change in ASC will be allowed 

for resource additions or reductions. 

Bonneville will allow a utility to submit 

stacks of individual resources that, 

when combined, meet the materiality 

threshold. However, each resource in 

the stack must result in an increase of 

Base Period ASC of 0.5 percent or more. 

(4) At the time the utility submits its 

Appendix 1 filing, the utility will 

provide its forecast of major new 

resource addition(s) and all associated 

costs. The forecast will cover the period 

from the end of the Base Period to the 

end of the Exchange Period. 

(5) Bonneville will calculate new 

transmission wheeling revenues 

associated with new transmission 

investment using the following formula: 

NTWR = WR (before additions) * [NTP 

(before additions) + NTA) NTP 

(before additions)] 

Where: 

NTWR = New transmission wheeling 

revenues 

WR (before additions) = wheeling revenues 

(before additions) 

NTP (before additions) = Net Transmission 

Plant (before additions) 

NTA = new transmission additions 

(6) The forecast of the major new 

resource costs to be included in the 

utility’s Exchange Period ASC will be 

reviewed and determined during the 

Review Period. 

(7) All major new resources included 

in an ASC calculation prior to the start 

of the Exchange Period will be projected 

forward to the midpoint of the Exchange 

Period. 

(8) For each major new resource 

addition forecast to be available to meet 

regional retail load during the Exchange 

Period, Bonneville will calculate the 

difference in ASC between the ASC 

without the new resource and the ASC 

with the new resource (the ASC delta) 

at the midpoint of the Exchange Period. 

(9) When the resource comes online, 

Bonneville will add the ASC delta to the 

utility’s existing ASC to determine its 

new ASC. 

(10) The steps in paragraphs (c)(3) 

through (c)(9) of this section will be 

used for resources that are sold, 

transferred, or retired. 

(11) Bonneville will escalate the Base 

Period average per-MWh cost of 

Distribution Plant forward to the 

midpoint of the Exchange Period, and 

use the escalated average cost to 

determine the distribution-related cost 

of meeting load growth since the Base 

Period. This cost will be included in the 

Exchange Period ASC. 

(12) Bonneville will issue procedural 

rules to ensure the confidentiality of 

information provided by utilities 

regarding any new major resource 

additions as part of its review process. 

Bonneville will provide parties with an 

opportunity to comment on the rules 

prior to their implementation in the 

review process. Failure to provide 

needed information may result in 

exclusion of the related costs from the 

utility’s ASC. However, as is the case for 

other utilities that do not have major 

resource additions in a particular year, 

load growth will be assumed to be met 

with purchases in the wholesale market, 

as described in paragraph (e) of this 

section. What the utility loses by not 

supplying confidential resource data is 

the difference between the cost of the 

resource and the price of electricity in 

the wholesale market. 

(d) Forecasted Contract System and 

Exchange Load. All utilities are required 

to provide a forecast of their Contract 

System Load and associated Exchange 

Load, as well as a current distribution 

loss study as described in endnote e/ of 

Appendix 1, with their Appendix 1 

listing. The load forecast for Contract 

System Load and Exchange Load will be 


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provided on a monthly basis for the 

Exchange Period. 

(e) Load Growth not met by new 

resource additions. All forecast load 

growth not met by new resource 

additions will be met by purchased 

power at the forecasted utility-specific, 

short-term purchased power price. 

(1) The utility’s forecast load growth 

will be met with market purchases 

priced at the utility’s forecast shortterm, purchased power price unless the 

utility forecasts major resource 

additions. 

(2) In the event of major resource 

additions, forecast load growth will be 

met by the new resource. If the new 

resource is less than total forecast load 

growth, the unmet load growth will be 

met with market purchases priced at the 

utility’s forecast short-term, purchased 

power price. 

(3) In the event that the power 

provided by a new resource exceeds the 

utility’s forecast load growth, the excess 

will be sold as surplus power into the 

market, and priced at the utility’s 

forecast sales for resale price as 

determined in paragraph (b) of this 

section. 

(f) Changes to service territory. In the 

event a utility forecasts that it will 

acquire a new service territory, or lose 

a portion of its service territory, and the 

resulting change in ASC falls within the 

2.5 percent or greater materiality 

threshold, the utility will submit two 

ASC filings. 

(1) A Base Period ASC that does not 

reflect the acquisition or loss of service 

territory; and 

(2) A second filing that incorporates 

the following: 

(i) The forecast of the increase or 

reduction in Contract System Load 

associated with the acquisition or 

reduction in service territory. 

(ii) The forecast of the increase or 

reduction in Contract System Costs 

associated with the acquisition or 

relinquishment of the service territory. 

(iii) In addition to including the 

forecast of capital and operating cost 

increases or reductions associated with 

the change in service territory, the 

utility must forecast the changes in 

purchased power expense, sales-forresale credit and other costs based on 

the changes in the service territory. 

(iv) Because the date of the actual 

change to the utility’s service territory 

could differ from the forecast date used 

to determine the ASC during the Review 

Period, Bonneville will not adjust the 

utility’s ASC until the change in service 

territory takes place. 

(g) ASC determination for customerowned utilities that elect to execute 

Regional Dialogue High Water Mark 

contracts. Bonneville will use the 

following approach: 

(1) Use the RHWM System Load as 

determined in the Tiered Rates 

methodology process. 

(2) Determine the RHWM 

Exchangeable Load (Residential/Small 

Farm Load). 

(3) During the ASC review process, 

the utility must submit the data 

necessary to determine the fullyallocated unit cost of resources in excess 

of the resource amounts used to 

calculate its CHWM. 

(4) Calculate the utility’s total 

unadjusted Contract System Cost. 

(5) Calculate a load growth credit, i.e., 

{(Current System Load minus RHWM 

System Load) * Unit costs from 

paragraph (g)(3) of this section}. 

(6) Total Exchange Contract System 

Cost = Total Unadjusted Contract 

System Cost minus load growth revenue 

credit from paragraph (g)(5) of this 

section. 

(7) HWM Average System Cost = Total 

Exchangeable Contract System Cost/ 

RHWM System Load. 

(h) Filing of Appendix 1. Utilities 

must file ASC information by June 1 

each year, as required in § 301.2, for 

Bonneville’s review and determination 

of a Base Period ASC. Utilities will file 

multiple, contingent, Base Period ASC 

filings to reflect changes to service 

territories as required in paragraph (f) of 

this section. 

§ 301.6 Change in Average System Cost 

methodology. 

(a) The Administrator, at his or her 

discretion, or upon written request from 

three-quarters of the utilities that are 

parties to contracts authorized by 

section 5(c) of the Northwest Power Act, 

or from three-quarters of Bonneville’s 

preference customers, or from threequarters of Bonneville’s direct-service 

industrial customers may initiate a 

consultation process as provided in 

section 5(c) of the Northwest Power Act. 

After completion of this process, the 

Administrator may file the new ASC 

methodology with the Commission. 

However, the Administrator will not 

initiate any consultation process until 

one year of experience has been gained 

under the then-existing ASC 

methodology, one year after the thenexisting ASC methodology is adopted by 

Bonneville and approved by the 

Commission, through interim or final 

approval, whichever occurs first. 

(b) The Administrator may, from time 

to time, issue interpretations of the ASC 

methodology. The Administrator may 

modify the functionalization code of 

any Account to comply with the 

limitations identified in section 

5(c)(7)(A)–(C) of the Northwest Power 

Act or to conform to Commission 

revisions to the Uniform System of 

Accounts. 

§ 301.7 Sample time line review 

procedures. 

(a) Bonneville’s ASC review process 

of the utilities’ Appendix 1 occurs only 

in the year before Bonneville establishes 

new Wholesale Power Rate Schedules. 

However, utilities are required to file an 

Appendix 1 by June 1 of each year so 

that Bonneville can maintain current 

data. 

(b) The following schedule is a 

generic schedule that is representative 

of the time line for the ASC review 

process. Each spring in the year prior to 

Bonneville’s implementation of new 

Wholesale Power Rates, Bonneville will 

post a detailed schedule incorporating 

the applicable holidays and weekends. 

Deadlines end at 5 p.m., Pacific 

Prevailing Time, of the due date. 

(1) June 1—Utilities file electronic 

Appendix 1s with Bonneville. 

(2) June 7—Deadline to file petitions 

to intervene with Bonneville. 

(3) June 10—Bonneville grants or 

denies petitions to intervene. 

(4) June 11—Begin Data Request 

period. 

(5) TBD—Workshop(s) on utilities’ 

Appendix 1 filings. 

(6) Aug 22—End Data Request period. 

(7) Aug 27—Deadline for Bonneville’s 

and parties’ issue lists on utilities’ 

filings. 

(8) Sept 10—Deadline for reply issue 

lists from all parties on utilities’ filings. 

(9) Sept 16—Workshop to discuss 

issue lists on utilities’ filings. 

(10) Sept 19—Deadline to request oral 

argument. 

(11) Sept 22—Bonneville grants or 

denies requests for oral argument. 

(12) Oct 1—Oral argument (if 

granted). 

(13) Oct 19—Bonneville publishes 

draft ASC Report. 

(14) Nov 1—Deadline for utilities’ and 

parties’ comments on draft ASC Report. 

(15) Nov 14—Administrator issues 

final ASC Report. 

§ 301.8 Appendix 1 instructions. 

(a) Appendix 1 is the form on which 

a utility reports its Contract System 

Costs, Contract System Loads, and other 

necessary data for the calculation of 

ASC. Appendix 1 is an electronic 

template consisting of seven schedules 

and several supporting files that must be 

completed by the utility in accordance 

with these instructions and the 

provisions of the endnotes following the 

schedules. 

(b) Appendix 1 filings must be 

accompanied by an attestation statement 


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of the Chief Financial Officer of the 

utility or other responsible official who 

possesses the financial and accounting 

knowledge necessary to complete the 

attestation statement. 

(c) The primary source of data for the 

investor-owned utilities’ Appendix 1 

filings is the utility’s prior year Form 1 

filing with the Commission. Any items 

not applicable to the utility must be 

identified. 

(d) For consumer-owned utilities that 

do not follow the Commission’s 

Uniform System of Accounts, filings 

must include reconciliation between 

utility accounts and the items allowed 

as Contract System Costs. In addition, 

the cost-of-service report must be 

reviewed by an independent accounting 

or consulting firm. The cost-of-service 

report must be accompanied by a report 

from an independent accounting firm or 

consulting firm that outlines the review 

work that was performed in preparing 

the cost-of-service report along with an 

assurance statement that the 

information contained in the cost-ofservice report is presented fairly in all 

material respects. 

(e) The Appendix 1 template is 

available electronically at http:// 

www.bpa.gov/corporate/finance/ascm/, 

or its successor site. The primary 

schedules are: 

(1) Schedule 1: Plant Investment/Rate 

Base 

(2) Schedule 1A: Cash Working Capital 

(3) Schedule 2: Capital Structure and 

Rate of Return 

(4) Schedule 3: Expenses 

(5) Schedule 3A: Taxes 

(6) Schedule 3B: Other Included Items 

(7) Schedule 4: Average System Cost 

(f) The filing utility must reference 

and attach work papers, documentation, 

and other required information that 

supports costs and loads, including 

details of allocation and 

functionalization. All references to the 

Commission’s Accounts are the 

Commission’s Uniform System of 

Accounts as of July 1, 2006, or as 

amended by subsequent Commission 

actions. The costs includable in the 

attached schedules are those includable 

by reason of the definitions in the 

Commission’s Accounts. If the 

Commission’s Accounts are later revised 

or renumbered, any changes will be 

incorporated into Appendix 1 by 

reference, except to the extent 

Bonneville determines that a particular 

change results in a change in the type 

of costs allowable for Residential 

Exchange Program purposes. In that 

event, Bonneville will address the 

changes, including escalation rules, in 

its review process for the following 

Exchange Period. 

(g) Bonneville may require a utility to 

account for all transactions with 

affiliated entities as though the affiliated 

entities were owned in whole or in part 

by the utility, if necessary, to properly 

determine and/or functionalize the 

utility’s costs. 

(h) A utility operating in more than 

one Pacific Northwest Jurisdiction must 

file one Appendix 1. 

(i)(1) A utility operating in 

jurisdictions outside the Pacific 

Northwest Jurisdiction must allocate its 

total system costs among its 

jurisdictions within the Pacific 

Northwest and outside the Pacific 

Northwest in accord with the same 

allocation methods and procedures used 

by the Regulatory Body(ies) to establish 

jurisdictional costs and resulting 

revenue requirements. The utility’s 

Appendix 1 filing must include details 

of the allocation. 

(2) The allocation must exclude all 

costs of additional resources used to 

meet loads outside the region, as 

required by section 5(c)(7) of the 

Northwest Power Act. All schedule 

entries and supporting data must be in 

accord with Generally Accepted 

Accounting Principles and Practices as 

these principles and practices apply to 

the electric utility industry. 

(j) A utility must file an attestation 

statement with each Appendix 1 filing 

and supporting documentation for each 

Review Period. 

§ 301.9 Functionalization of Average 

System Cost methodology. 

(a) Functionalization of each account 

included in a utility’s ASC must be 

according to the functionalization 

prescribed in Table 1, Functionalization 

and Escalation Codes. Direct analysis on 

an account may be performed only if 

Table 1 states specifically that a utility 

may perform a direct analysis on the 

account with the exception of 

conservation costs. Utilities will be able 

to functionalize all conservation-related 

costs to Production, regardless of the 

Account in which they are recorded. 

The direct analysis must be consistent 

with the directions provided in this 

section. 

(b) The functionalization codes are: 

(1) DIRECT—Direct Analysis. 

(2) PROD—Production. 

(3) TRANS—Transmission. 

(4) DIST—Distribution/Other. 

(5) PTD—Production, Transmission, 

Distribution/Other Ratio. 

(6) TD—Transmission, Distribution/ 

Other Ratio. 

(7) GP—General Plant Ratio. 

(8) GPM—General Plant Maintenance 

Ratio. 

(9) PTDG—Production, Transmission, 

Distribution/Other, General Plant 

Ratio. 

(10) LABOR—Labor Ratio. 

(c) Functionalization process. 

(1) Functionalization of certain 

accounts may be based on direct 

analysis or with a default ratio 

associated with that specific account as 

shown in Table 1. Once a utility uses a 

specific functionalization method for an 

account, the utility may not change the 

functionalization for that account 

without prior written approval from 

Bonneville. 

(2) The utility must submit with its 

Appendix 1 all work papers, 

documents, or other materials that 

demonstrate that the functionalization 

under its direct analysis assigns costs 

based upon the actual and/or intended 

functional use of those items. Failure to 

submit the documentation will result in 

the entire account being functionalized 

to Distribution/Other, or Production, or 

Transmission, as appropriate. 

(d) Functionalization methods. 

(1) Direct analysis, if allowed or 

required by Table 1, assigns costs to the 

Production, Transmission, and/or 

Distribution function of the utility. The 

only exception to this requirement is for 

conservation-related costs. Utilities will 

be able to identify and functionalize to 

Production any conservation-related 

costs, irrespective of the Account in 

which they are recorded. The analysis is 

subject to Bonneville review and 

approval. Once a utility uses a specific 

functionalization method for an 

Account, the utility may not change the 

functionalization for that Account 

without prior written approval from 

Bonneville. 

(2) Bonneville will not allow utilities 

to use a combination of direct analysis 

and a prescribed functionalization 

method for the same Account. The 

utilities can develop and use a 

functionalization ratio, or use a 

prescribed functionalization method if 

the utility through direct accounts can 

justify how the ratio reflects the 

functional nature of the costs included 

in any Account or cost item being 

functionalized by the ratio. 

(3) Utilities that wish to include 

advertising and promotion costs related 

to conservation will use direct analysis. 

If a utility records conservation costs in 

an Account that is normally 

functionalized to Distribution/Other, the 

utility will identify and document the 

conservation-related costs included in 

the Account, and the balance of the 

costs will be functionalized to 

Distribution/Other. The presence of 

conservation-related costs in an 


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Account does not authorize the utility to 

perform a direct analysis on the entire 

Account. This option allows a utility to 

assign costs in the specified Account to 

Production, Transmission and/or 

Distribution/Other based on analysis 

and support from the utility that 

demonstrates the cost assignment is 

appropriate. The utility must submit 

with its ASC filing all work papers, 

documents, and other materials that 

demonstrate the functionalization 

contained in its direct analysis and 

assigns costs based upon the actual and/ 

or intended functional use of those 

items. Failure to submit the 

documentation will result in the entire 

account being functionalized to 

Distribution/Other for all schedules 

with the exception of items included in 

Schedule 3B, Other Included Items, 

where certain accounts must be 

functionalized to Production as 

appropriate. 

BILLING CODE 6717–01–P 


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Table 1 to Part 301—Functionalization 

and Escalation Codes 


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Appendix 1 to Part 301—Bonneville 

Power Administration Residential 

Purchase and Sales Agreement 


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Appendix 2 to Part 301—Chief 

Financial Officer Attestation 


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[FR Doc. E8–23676 Filed 10–9–08; 8:45 am] 

BILLING CODE 6717–01–C 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 180 

[EPA–HQ–OPP–2002–0043; FRL–8376–1] 

Pesticide Tolerance Nomenclature 

Changes; Technical Amendments 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; Technical 

Amendments. 

SUMMARY: This document makes minor 

technical revisions to the terminology of 

certain commodity terms listed under 

40 CFR part 180, subparts A, C, and E. 

EPA is taking this action to establish a 

uniform listing of commodity terms 

throughout part 180. 

DATES: This regulation is effective 

October 10, 2008. Objections and 

requests for hearings must be received 

on or before December 9, 2008, and 

must be filed in accordance with the 

instructions provided in 40 CFR part 

178 (see also Unit I.C. of the 

SUPPLEMENTARY INFORMATION ). 

ADDRESSES: EPA has established a 

docket for this action under docket 

identification (ID) number EPA–HQ– 

OPP–2002–0043. To access the 

electronic docket, go to http:// 

www.regulations.gov, select ‘‘Advanced 

Search,’’ then ‘‘Docket Search.’’ Insert 

the docket ID number where indicated 

and select the ‘‘Submit’’ button. Follow 

the instructions on the regulations.gov 

website to view the docket index or 

access available documents. All 

documents in the docket are listed in 

the docket index available in 

regulations.gov. Although listed in the 

index, some information is not publicly 

available, e.g., Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available in the electronic docket at 

http://www.regulations.gov, or, if only 

available in hard copy, at the OPP 

Regulatory Public Docket in Rm. S– 

4400, One Potomac Yard (South Bldg.), 

2777 S. Crystal Dr., Arlington, VA. The 

Docket Facility is open from 8:30 a.m. 

to 4 p.m., Monday through Friday, 

excluding legal holidays. The Docket 

Facility telephone number is (703) 305– 

5805. 

FOR FURTHER INFORMATION CONTACT: 

Stephen Schaible, Registration Division 

(7505P), Office of Pesticide Programs, 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460–0001; telephone number: 

(703) 308-9362; e-mail address: 

schaible.stephen@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this Action Apply to Me? 

You may be potentially affected by 

this action if you are an agricultural 

producer, food manufacturer, or 

pesticide manufacturer. Potentially 

affected entities may include, but are 

not limited to those engaged in the 

following activities: 

• Crop production (NAICS code 111). 

• Animal production (NAICS code 

112). 

• Food manufacturing (NAICS code 

311). 

• Pesticide manufacturing (NAICS 

code 32532). 

This listing is not intended to be 

exhaustive, but rather to provide a guide 

for readers regarding entities likely to be 

affected by this action. Other types of 

entities not listed in this unit could also 

be affected. The North American 

Industrial Classification System 

(NAICS) codes have been provided to 

assist you and others in determining 

whether this action might apply to 

certain entities. If you have any 

questions regarding the applicability of 

this action to a particular entity, consult 

the person listed under FOR FURTHER

INFORMATION CONTACT. 

B. How Can I Access Electronic Copies 

of this Document? 

In addition to accessing an electronic 

copy of this Federal Register document 

through the electronic docket at http:// 

www.regulations.gov, you may access 

this Federal Register document 

electronically through the EPA Internet 

under the ‘‘Federal Register’’ listings at 

http://www.epa.gov/fedrgstr. You may 

also access a frequently updated 

electronic version of EPA’s tolerance 

regulations at 40 CFR part 180 through 

the Government Printing Office’s pilot 

e-CFR site at http://www.gpoaccess.gov/ 

ecfr. 

C. Can I File an Objection or Hearing 

Request? 

Under section 408(g) of FFDCA, any 

person may file an objection to any 

aspect of this regulation and may also 

request a hearing on those objections. 

You must file your objection or request 

a hearing on this regulation in 

accordance with the instructions 

provided in 40 CFR part 178. To ensure 

proper receipt by EPA, you must 

identify docket ID number EPA–HQ– 

OPP–2002–0043 in the subject line on 

the first page of your submission. All 

requests must be in writing, and must be 

mailed or delivered to the Hearing Clerk 

as required by 40 CFR part 178 on or 

before December 10, 2008. 

In addition to filing an objection or 

hearing request with the Hearing Clerk 

as described in 40 CFR part 178, please 

submit a copy of the filing that does not 

contain any CBI for inclusion in the 

public docket that is described in 

ADDRESSES. Information not marked 

confidential pursuant to 40 CFR part 2 

may be disclosed publicly by EPA 

without prior notice. Submit this copy, 

identified by docket ID number EPA– 

HQ–OPP–2002–0043, by one of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

• Mail: Office of Pesticide Programs 

(OPP) Regulatory Public Docket (7502P), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460–0001. 

• Delivery: OPP Regulatory Public 

Docket (7502P), Environmental 

Protection Agency, Rm. S–4400, One 

Potomac Yard (South Bldg.), 2777 S. 

Crystal Dr., Arlington, VA. Deliveries 

are only accepted during the Docket’s 

normal hours of operation (8:30 a.m. to 

4 p.m., Monday through Friday, 

excluding legal holidays). Special 

arrangements should be made for 

deliveries of boxed information. The 

Docket Facility telephone number is 

(703) 305–5805. 

II. Background 

A. What Action is the Agency Taking? 

EPA’s Office of Pesticide Programs 

(OPP) has developed a commodity 

vocabulary database entitled ‘‘Food and 

Feed Commodity Vocabulary.’’ The 

database was developed to consolidate 

all the major OPP commodity 

vocabularies into one standardized 

vocabulary. As a result, all future 

pesticide tolerances issued under 40 

CFR part 180 will use the ‘‘preferred 

commodity term’’ as listed in the 

aforementioned database. Previously, 

seven documents in a series of 

documents revising the terminology of 

commodity terms currently in 

tolerances in 40 CFR part 180 have been 

published. Final Rules, revising 

pesticide tolerance nomenclature, were 

published in the Federal Register on 

June 19, 2002 (67 FR 41802) (FRL– 

6835–2); June 21, 2002 (67 FR 42392) 

(FRL–7180–1); July 1, 2003 (68 FR 


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