47052 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

transferable instruments for the purpose of making 

transfers to third parties—i.e., to hold deposits 

commonly called NOW accounts. 

Paragraph (2) of 12 U.S.C. 1832(a) provides: 

‘‘Paragraph (1) shall apply only with respect to 

deposits or accounts which consist solely of funds 

in which the entire beneficial interest is held by one 

or more individuals or by an organization which is 

operated primarily for religious, philanthropic, 

charitable, educational, political, or other similar 

purposes and which is not operated for profit, and 

with respect to deposits of public funds by an 

officer, employee, or agent of the United States, any 

State, county, municipality, or political subdivision 

thereof, the District of Columbia, the 

Commonwealth of Puerto Rico, American Samoa, 

Guam, any territory or possession of the United 

States, or any political subdivision thereof.’’ 

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

2 16 U.S.C. 839c(c)(1). 

3This rate is generally a lower rate. 

4See 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)). 

5 16 U.S.C. 839c(c)(7). 

6 16 U.S.C. 839c(c)(7)(A)–(C). 

7 Methodology for Sales of Electric Power to 

Bonneville Power Administration, Order No. 400, 

FERC Stats. & Regs. ¶ 30,601, at 31,161–62 (1984), 

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

(1985). 

8 16 U.S.C. 824, 824d, 824e. 

9Order No. 400, FERC Stats. & Regs. ¶ 30,601 at 

31,161–62. 

■ 3. Section 329.102 is amended by 

revising the introductory text to read as 

follows: 

§ 329.102 Deposits described in 

§ 329.1(b)(3). 

This interpretive rule explains the 

proviso of § 329.1(b)(3). 

* * * * * 

Dated this 9th day of September 2009. 

By order of the Board of Directors. 

Federal Deposit Insurance Corporation. 

Robert E. Feldman, 

Executive Secretary. 

[FR Doc. E9–22070 Filed 9–14–09; 8:45 am] 

BILLING CODE 6714–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 301 

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

000; Order No. 726; 128 FERC ¶ 61,222] 

Sales of Electric Power to the 

Bonneville Power Administration; 

Revisions to Average System Cost 

Methodology 

Issued September 4, 2009. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: The Federal Energy 

Regulatory Commission grants final 

approval to the revised methodology for 

determining the average system cost 

(ASC) used by Bonneville Power 

Administration in its Residential 

Exchange Program. 

DATES: Effective Date: This final rule is 

effective October 15, 2009. 

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: Jon Wellinghoff, 

Chairman; Suedeen G. Kelly, Marc Spitzer 

and Philip D. Moeller. 

Order No. 726 

Final Rule 

Issued September 4, 2009 

1. The Federal Energy Regulatory 

Commission grants final approval of the 

Bonneville Power Administration’s 

(Bonneville) 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

I. Background 

2. Section 5(c) of the Northwest Power 

Act provides for a Residential Exchange 

Program, which is designed to make the 

benefits of Bonneville’s relatively low 

preference power rates available to 

residential customers of investor-owned 

utilities in the Pacific Northwest. 

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.2 Bonneville then sells the 

same amount of power back to the 

utility at Bonneville’s priority firm 

exchange rate.3 The power exchange is 

generally viewed as a paper 

transaction.4 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. 

Instead, the Northwest Power Act grants 

Bonneville’s Administrator the 

authority to establish a methodology for 

determining and 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.5

The Northwest Power Act, however, 

directs 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 cost of 

any generating facility which is 

terminated prior to initial operation.6

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 Northwest 

Power 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.7

5. The Commission’s second role in 

the exchange program arises from its 

Federal Power Act (FPA) 8 responsibility 

to review the wholesale sales rates of 

individual public utilities, essentially 

investor-owned utilities; the 

Commission reviews the rates for such 

sales from the investor-owned 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 accept 

under the FPA any sale to Bonneville 

that is based on application of an 

approved ASC methodology.9

6. On July 14, 2008, Bonneville filed 

a proposed revised ASC methodology to 

replace the then-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 


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10See 18 CFR Part 301. 

11The 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 the 

comments and protests. Additionally, Bonneville 

filed an errata correction to its original filing on 

September 12, 2008 (September errata filing). 

12Comments were due on or before November 10, 

2008. See 73 FR 60,105 (Oct. 10, 2008). In response 

to a request by Bonneville the Commission 

subsequently provided an opportunity for reply 

comments. See Appendix A (providing a list of 

commenters). Bonneville filed an answer to the 

comments. 

13For investor-owned utilities, the ASC 

methodology allows the costs of all non-Federal 

resources to be included in their average system 

cost calculations. Investor-owned utilities also are 

permitted to use their retail load to determine their 

average system cost. On the other hand, consumerowned utilities that sign new power sales contracts 

with Bonneville that are offered under Bonneville’s 

Regional Dialogue process are subject to limitations 

on the non-Federal resource costs and the retail 

loads that can be used to calculate their average 

system cost. 

14A deemer provision is a contractual provision 

that dates from the 1981 Residential Purchase and 

Sales Agreement, which was the first contract that 

implemented Bonneville’s Residential Exchange 

Program. The provision was designed to address the 

situation where an exchanging utility’s average 

system cost falls below Bonneville’s Power Firm 

Exchange rate, resulting in ‘‘negative’’ Residential 

Exchange Program benefits. Rather than have a 

utility pay Bonneville, the exchanging utility could 

‘‘deem’’ its average system cost equal to the Power 

Firm Exchange Rate. The negative difference that 

would have otherwise been paid to Bonneville is 

then tracked in a separate ‘‘deemer account.’’ An 

outstanding balance in the deemer account is 

referred to as a ‘‘deemer balance.’’ An exchanging 

utility is required to pay off this balance through 

reductions in future positive Residential Exchange 

Program benefits before it can receive further 

Residential Exchange Program payments. Certain 

exchanging utilities accrued deemer balances under 

the 1981 Residential Purchase and Sales 

Agreements. 

15 Idaho Power also challenges the deemer 

mechanism for the same reasons as Idaho PUC. 

Filing).10 In its July 2008 Filing (which 

was corrected on September 12, 2008),11

Bonneville stated that this was the first 

revision to its ASC methodology in 24 

years, and reflected changes in the 

energy industry that had transpired 

during that time. 

7. In its July 2008 Filing, Bonneville 

explained that the revised ASC 

methodology retained characteristics of 

the then-current ASC methodology. 

Bonneville explained, further, that the 

key differences were how average 

system costs are calculated as well as 

the substance of the costs included and 

excluded from the average system costs 

calculation. Bonneville stated that the 

revised ASC methodology adopted a 

streamlined approach to the average 

system cost calculations by using a 

different source of average system cost 

data, i.e., FERC Form 1 data, instead of 

state retail rate orders. Bonneville noted 

that, in addition, it proposed to adjust 

average system costs less frequently. 

Bonneville asserted that the revised 

ASC methodology allowed 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 operated. 

8. Bonneville also explained that it 

was proposing to establish a two-year 

average system cost period that would 

correspond with its two-year wholesale 

power rate periods. Bonneville 

explained, further, that each utility’s 

average system cost would stay fixed 

except for pre-determined adjustments 

to reflect the costs of new resources 

incurred during the rate/exchange 

period. According to Bonneville, this 

feature would lessen the number of 

average system cost filings reviewed by 

Bonneville and the Commission. 

9. Bonneville explained that the 

revised ASC methodology also changed 

the average system cost treatment of 

certain costs. Bonneville stated that it 

was 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. 

10. Bonneville requested Commission 

approval of this new ASC methodology 

by October 1, 2008 to coordinate with 

the initiation of the Residential 

Exchange Program. 

11. On September 30, 2008, the 

Commission conditionally approved in 

an interim rule Bonneville’s proposed 

ASC methodology. The Commission 

also requested comments on whether it 

should approve the ASC methodology 

on a final basis as proposed by 

Bonneville.12

II. Discussion 

12. For the reasons discussed below, 

the Commission grants final approval of 

Bonneville’s new ASC methodology, as 

amended, with minor editorial changes. 

A. Introduction 

13. Bonneville proposed an amended 

ASC methodology in its comments. 

Bonneville states that its amended 2008 

ASC methodology comprises the 

following three main components: (1) 

Provisions related to the calculation of 

the Base Period average system cost (in 

amended §§ 301.8, 301.9, and the 

Appendix 1 Endnotes); (2) provisions 

relating to the escalation (or change) of 

the Base Period average system cost to 

the Exchange Period average system cost 

(amended § 301.5); and (3) provisions 

relating to Bonneville’s average system 

review process and procedures 

(amended §§ 301.3, 301.4 and 301.7). 

Comments 

14. The Public Utility District No. 1 of 

Clark County, Washington and the 

Public Utility District No. 1 of Grays 

Harbor County, Washington (Districts) 

challenge Bonneville’s calculation of 

average system cost in a different 

manner for investor-owned utilities and 

for consumer-owned utilities 

participating in the Residential 

Exchange Program.13 The Districts argue 

that, under prior ASC methodologies, 

investor-owned utilities and consumerowned utilities were able to include the 

same non-Federal resource costs and the 

same retail loads for the calculation of 

their average system costs. The Districts 

claim that now, in contrast, the investorowned utilities can include the costs of 

all non-federal resources and their 

entire retail loads, and the consumerowned utilities face limitations on their 

recovery of the costs of non-federal 

resources and limitations on their retail 

loads. The Districts challenge 

Bonneville’s rationale offered to support 

this different treatment, i.e., that 

allowing consumer-owned utilities to 

participate fully in Bonneville’s 

Residential Exchange Program would 

frustrate its policy goal of tiering or 

separating the costs of existing Federal 

resources from future resource costs for 

purposes of setting its Priority Firm 

Rate. The Districts argue that all utilities 

must be treated in the same manner, and 

that Bonneville has other means to 

implement its policy goal of tiering its 

resource costs. The Districts, therefore, 

request the Commission to reject 

Bonneville’s filing. 

15. Idaho Public Utility Commission 

(Idaho PUC) supports Bonneville’s 

revised ASC methodology. Idaho PUC, 

however, challenges the deemer 

mechanism 14 that is used in 

determining a utility’s average system 

cost.15 Idaho PUC notes that, when it 

challenged this mechanism in 

Bonneville’s stakeholder process to 

develop this revised ASC methodology, 

Bonneville declined to consider the 

challenge because the mechanism is not, 

in fact, part of the ASC methodology, 

but rather is part of the Residential 

Purchase and Sales Agreements between 

Bonneville and its customers. Idaho 

PUC disagrees, and requests the 


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47054 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

16The Tiered Rates methodology implements a 

new tiered rate structure with one set of rates (Tier 

1) for public bodies, cooperatives and Federal 

agencies (preference customers) that recovers the 

costs of Bonneville’s current generating system and 

programs, including the Residential Exchange 

Program. These customers will be limited to the 

amount of power than can be purchased at Tier 1 

rates. Another set of rates (Tier 2) will be 

established to recover the costs of new generating 

resources. Preference customers will be able to 

purchase any requirements that remain after 

purchasing up to their maximum at Tier 1 rates. 

The Tiered Rates methodology is structured to keep 

separate the costs of resources whose costs are 

recovered through Tier 1 rates from the costs of 

resources whose costs are recovered through Tier 2 

rates. Bonneville’s Tiered Rates methodology is 

currently pending in Docket No. EL09–12–000. 

17See 16 U.S.C. 839c(c)(7); see Districts 

comments at 6 (‘‘the Northwest Power Act gives 

Bonneville the responsibility of developing the 

methodology for calculating the average system cost 

of each participating utility’’). 18See 16 U.S.C. 839c(c)(1), (7). 19See 16 U.S.C. 839c(c)(7). 20See Order No. 400, FERC Stats. & Regs. 

¶ 30,601 at 31,163–64 (discussing, inter alia, the 

deference owed to Bonneville as well as Aluminum 

Co. of America v. Central Lincoln Peoples’ Utility 

District, 104 S. Ct. 2472, 2480–2483 (1984)); accord 

Sales of Electric Power to Bonneville Power 

Administration, Metholology and Filing 

Requirements, Order No. 337, FERC Stats. & Regs. 

¶ 30,506, at 30,738–39 (1983). 

21See 18 CFR 35.30 and 35.31; accord Order No. 

400, FERC Stats. & Regs. ¶ 30,601 at 31,161–62; 

Order No. 337, FERC Stats. & Regs. ¶ 30,506 at 

30,738–39. 

22See Order No. 337, FERC Stats. & Regs. 

¶ 30,506 at 30,738 (Commission can disapprove 

proposed ASC methodology only if it is 

inconsistent with Northwest Power Act). 

Commission to reject use of the deemer 

mechanism. 

Bonneville’s Answer 

16. Bonneville argues that the 

Districts mischaracterize the ASC 

methodology as applied to consumerowned utilities. It asserts that eligible 

consumer-owned utilities may choose to 

exchange all of their eligible non-federal 

resources with Bonneville, provided 

they execute a Residential Purchase and 

Sales Agreement. It states, further, that 

it never proposed to exclude the costs 

of eligible, non-federal resources of 

consumer-owned utilities from the 

average system cost calculation for 

purchases under that agreement. 

Bonneville also argues that the ASC 

methodology excludes the non-federal 

resources of the consumer-owned 

utilities from the calculation of the 

average system cost only to the extent a 

consumer-owned utility chooses to 

purchase power from Bonneville in the 

future under a so-called Regional 

Dialogue High Water Mark Contract 

(CHWM contract) provided to 

Bonneville’s preference customers 

under its Tiered Rates methodology.16

Bonneville notes that the CHWM 

contract is just one type of power sales 

agreement that Bonneville will offer. 

Bonneville states that, only if the 

consumer-owned utilities want a power 

sales contract that is connected to the 

Tiered Rates methodology, must they 

agree to limit the resources they 

exchange with Bonneville. 

17. Bonneville argues that the 

concerns of Idaho PUC and Idaho Power 

regarding the legality of the deemer 

provision are outside the scope of this 

rulemaking on the ASC methodology 

and should not be addressed in this 

proceeding. Bonneville asserts that the 

deemer provision is a provision in the 

Residential Purchase and Sales 

Agreement, and, as such, should be 

addressed in other forums. Bonneville 

adds that the Residential Purchase and 

Sales Agreement provisions are 

currently undergoing a stakeholder 

review process in another proceeding 

pending before Bonneville. 

Commission Determination 

18. Initially, the Commission grants 

Bonneville’s request to amend proposed 

part 301, as requested by Bonneville in 

its comments on the interim rule. 

Bonneville’s requested amendments to 

part 301 of the Commission’s 

regulations, described in more detail 

below, revise and clarify Bonneville’s 

ASC methodology and review process as 

it applies to Bonneville’s customers. As 

Bonneville notes, it held a public 

workshop with its customers to discuss 

the amendments and requested 

comments from its customers. 

According to Bonneville, its customers 

did not object to the revisions in their 

comments, but did request further 

clarifications that it asserts it 

incorporated in its filing. 

19. The Commission approves 

Bonneville’s amended ASC 

methodology, with minor editorial 

changes, notwithstanding the Districts’ 

objections. We note that, while the 

Districts complain of inconsistent 

treatment, the Districts also recognize 

that, under the statute, Bonneville has 

the authority to address with its 

customers, investor-owned utilities as 

well as consumer-owned utilities, 

which resources to include in its ASC 

methodology.17 And the statute simply 

does not require the kind of consistency 

that Districts claim it does.18 In any 

event, if consumer-owned utilities 

choose to execute Residential Purchase 

and Sales Agreements, then they will be 

entitled to the kind of consistency the 

Districts seek. Moreover, the 

Commission’s role is limited to 

‘‘review[ing] and approv[ing]’’ the ASC 

methodology.19 As we noted in Order 

No. 400, Bonneville is entitled to 

‘‘considerable deference’’ both in its 

interpretations of the Northwest Power 

Act and its policy judgments under that 

Act.20 (The Commission’s regulations 

also provide that the Commission will 

accept under the FPA any sales to 

Bonneville that are based on application 

of an approved ASC methodology.21) 

The Commission is approving the ASC 

methodology because it conforms to the 

provisions of the Northwest Power 

Act.22 We find no compelling basis in 

the Districts’ comments for arriving at a 

different result. 

20. We also decline Idaho PUC’s 

request that we reject use of the deemer 

mechanism. We find that Idaho PUC’s 

challenge represents a collateral attack 

on Bonneville’s Residential Purchase 

and Sales Agreements between 

Bonneville and its customers, where 

that mechanism is found. Those 

agreements are not the subject of this 

rulemaking proceeding. 

B. Base Period Average System Cost 

Calculation 

21. Bonneville states that amended 

§§ 301.8, 301.9 and the Appendix 1 

Endnotes provide the process for 

calculating a utility’s Base Period 

average system cost. The Base Period 

average system cost is an average system 

cost calculated from data available 

during the Base Period, i.e., the calendar 

year of an investor-owned utility’s most 

recent FERC Form 1, or a consumerowned utility’s similar financial 

information. According to Bonneville, 

the Base Period average system cost is 

calculated by populating the schedules 

in Appendix 1 with cost and revenue 

data from the utility. An investor-owned 

utility primarily will rely on its most 

recent FERC Form 1 as its source of data 

(consumer-owned utilities will rely on 

similar data), using supplemental 

information for some particular areas. 

Bonneville notes that the Appendix 1 

tables (Excel spreadsheets) will 

automatically generate the utility’s Base 

Period average system cost. 

22. Bonneville states that amended 

§ 301.8 of Bonneville’s ASC 

methodology provides general 

instructions for completing Appendix 1. 

That section describes the sources of 

data that investor-owned utilities and 

consumer-owned utilities must use. It 

also describes the utility’s duty to 

provide its work papers and other 

documentation substantiating its 

calculations. The section also requires 

the utility to file an attestation from its 

Chief Financial Officer regarding the 

data. 

23. Bonneville states that amended 

§ 301.9 and Table 1 of Bonneville’s ASC 


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23The term ‘‘functionalization,’’ as used here, 

refers to the process of assigning a utility’s costs 

and revenues to the Production, Transmission, and 

Distribution/Other categories. 

24See, e.g., Avista comments at 4; Idaho Power 

comments at 5. 25See supra notes 19–22 and accompanying text. 

26See, e.g., APAC comments at 1–2. 

27See, e.g., WUTC comments at 6; Avista 

comments at 14–16; Idaho Power at 3–6. 

28See, e.g., WUTC comments at 7; Avista 

comments at 11; Idaho Power comments at 10. 

29See, e.g., Avista comments at 4–5; Idaho Power 

at 6–7. 

30See, e.g., Avista comments at 8; Portland 

General comments at 9; Idaho Power comments at 

10. 

31Avista comments at 9; Idaho Power comments 

at 11. 

methodology describe how the 

individual cost and revenue items in the 

utility’s Appendix 1 are divided into the 

Production, Transmission, and 

Distribution/Other categories. 

According to Bonneville, costs that are 

assigned to the Production and 

Transmission categories will be 

included in the utility’s average system 

cost calculation, i.e., in the Contract 

System Cost numerator of the average 

system cost equation. Costs assigned to 

the Distribution/Other category will not 

be included. Bonneville notes that, for 

the most part, the line items in the 

Appendix 1 will be automatically 

assigned to the Production, 

Transmission, and/or Distribution/Other 

categories by predefined ratios, referred 

to as functionalization 23 codes. 

24. According to Bonneville, for 

certain Accounts in Appendix 1, the 

utility will have the option of not using 

the default functionalization code. 

Instead, it may conduct a more detailed 

analysis to assign costs or revenues to 

the Production, Transmission, or 

Distribution/Other categories. 

Bonneville refers to this analysis as a 

‘‘direct analysis.’’ Bonneville states that 

Table 1 identifies the Accounts in 

Appendix 1 that may be evaluated 

under a direct analysis. Paragraphs (c) 

and (d) of amended § 301.9 require that 

a utility substantiate its direct analysis 

with documentation and other evidence, 

and that the utility, having opted to use 

a direct analysis on an Account, must 

continue to use a direct analysis on the 

Account in future Appendix 1 filings, 

unless Bonneville allows the utility to 

return to the default functionalization 

code. 

25. Bonneville notes that the 

Appendix 1 schedules and ratio tables 

are, in some instances, subject to special 

rules or requirements as described in 

the Endnotes to Appendix 1. The 

Endnotes provide substantive 

information about how certain line 

items in Appendix 1 will be treated. 

Comments 

26. Commenters challenge 

Bonneville’s decision to adjust a 

utility’s base year data by escalating the 

utility’s average system costs to the midpoint of Bonneville’s rate period.24

Commission Determination 

27. The Commission finds that 

commenters are challenging an element 

of Bonneville’s ASC methodology that is 

beyond the Commission’s scope of 

review of the methodology. As we have 

explained above, our role is a limited 

one—ensuring consistency with the 

Northwest Power Act. We are not 

otherwise authorized to challenge the 

Administrator’s decisions relating to the 

specifics of the ASC methodology.25

Moreover, Bonneville developed the 

amended ASC methodology through a 

stakeholder process with customers. 

The amended ASC methodology 

approved here represents the results of 

that collaboration. To the extent 

Bonneville and its customers find that 

any component of that ASC 

methodology needs further refinement, 

we anticipate that Bonneville and its 

customers will resolve the issue through 

further consultation as provided by the 

statute. 

C. Exchange Period Average System 

Cost Determination 

28. According to Bonneville, amended 

§§ 301.8, 301.9 and the Endnotes will be 

the core provisions it will use to 

determine a utility’s average system 

cost. Bonneville notes that the 

Commission will rely on those sections 

to evaluate whether Bonneville’s 

average system cost determinations are 

consistent with Bonneville’s 2008 ASC 

methodology. 

29. Bonneville explains that, once a 

utility’s Base Period is calculated and 

Bonneville determines that the utility 

has properly functionalized all of its 

costs, certain line items of the utility’s 

Appendix 1 are escalated to the 

beginning of, and then through, 

Bonneville’s subsequent wholesale 

power rate period (referred to as the 

Exchange Period). According to 

Bonneville, this ‘‘escalation step’’ is the 

second major component of 

Bonneville’s 2008 ASC methodology, 

and is a new feature unique to its 2008 

ASC methodology. According to 

Bonneville, this ‘‘escalation step’’ 

reduces the administrative burden by 

limiting changes to a utility’s average 

system cost once it is established in an 

average system cost review process. 

30. Section 301.5 of the amended 

2008 ASC methodology describes the 

method Bonneville and parties 

developed to calculate the utility’s 

average system cost. Bonneville uses 

industry standard escalators to escalate 

certain line items in the utility’s 

Appendix 1. Bonneville explains that, 

after the specified line items are 

escalated, the utility’s average system 

cost is recalculated. According to 

Bonneville, the resulting average system 

cost, i.e., the Exchange Period average 

system cost, is the average system cost 

Bonneville will use to determine the 

utility’s Residential Exchange Program 

benefits during Bonneville’s subsequent 

wholesale power rate period. Bonneville 

notes that the Exchange Period average 

system cost also is the average system 

cost that jurisdictional utilities file with 

the Commission for review. 

31. Amended § 301.5 also outlines the 

limited ways in which a utility’s average 

system cost may change during an 

Exchange Period. Bonneville states that 

its amended 2008 ASC methodology 

removes the connection between a 

utility’s request for a retail rate change 

and a change in its average system cost, 

thereby limiting the administrative 

burden for both Bonneville and the 

Commission. Bonneville states that the 

only time a utility’s average system cost 

may change once established for an 

Exchange Period is: (1) To account for 

major resource additions or reductions; 

or (2) to adjust for the loss or gain of 

service territory. Bonneville explains 

that, except for these limited 

circumstances, a utility’s average system 

cost is locked-in until the beginning of 

Bonneville’s next average system cost 

review process. 

Comments 

32. Commenters challenge core 

provisions of the ASC methodology that 

will be used to determine a utility’s 

average system cost, including but not 

limited to the following: (1) Use of FERC 

Form 1 data as the basis for calculating 

a utility’s average system cost; 26 (2) 

failure to include state income and 

revenue taxes in the average system cost 

determination, while including federal 

income taxes; 27 (3) failure to include a 

utility’s regulatory fees in Account 

928; 28 (4) failure to include replacement 

fuel for power (and replacement gas 

transportation) agreements as a major 

resource addition in ‘‘new resource 

costs;’’ 29 (5) treatment of requirement 

sales for resale in Account 447; 30 (6) 

inclusion of conflicting statements 

regarding the functionalization of 

customer expenses in Account 908; 31

and (7) failure to provide a methodology 

for determining average system costs for 

customer-owned utilities that elect to 


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32See, e.g., Avista comments at 12; Idaho Power 

comments at 14. 33See supra notes 19–22 and accompanying text. 34See Order No. 337, FERC Stats. & Regs. at 

¶ 30,506 at 30,738. 

35See, e.g., Avista comments at 5; Idaho Power 

comments at 7. 36See, e.g., Avista comments at 7; Idaho Power 

comments at 9. 37See supra notes 19–22 and accompanying text; 

accord Order No. 337, FERC Stats. & Regs. ¶ 30,506 

at 30,738. 38See APAC comments at 2. 

execute Regional Dialogue High Water 

Mark contracts.32

Commission Determination 

33. The Commission finds that 

commenters are challenging elements of 

Bonneville’s ASC methodology that are 

beyond the Commission’s scope of 

review. As we have explained above, 

our role is a limited one—ensuring 

consistency with the Northwest Power 

Act. We are not otherwise authorized to 

challenge the Administrator’s decisions 

relating to the specifics of the ASC 

methodology.33 Moreover, Bonneville 

developed the amended ASC 

methodology through a stakeholder 

process with customers. The amended 

ASC methodology approved here 

represents the results of that 

collaboration. To the extent Bonneville 

and its customers find that any 

component of that ASC methodology 

needs further refinement, we anticipate 

that Bonneville and its customers will 

resolve the issue through further 

collaboration as provided by the statute. 

D. Bonneville’s Review of a Utility’s 

Average System Cost Determination 

34. Amended §§ 301.3, 301.4, and 

301.7 provide the procedures and 

schedules Bonneville will use when 

reviewing a utility’s average system 

cost. Bonneville explains that a utility is 

required to file an Appendix 1 with 

Bonneville by June of the fiscal year 

prior to the beginning of Bonneville’s 

next wholesale power rate proceeding. 

Bonneville notes that it conducts its rate 

proceedings in the fall of the year prior 

to the expiration of its rates. Bonneville 

notes, further, that in the years it is not 

proposing to change wholesale power 

rates, utilities are required to file an 

informational Appendix 1 with 

Bonneville. These informational filings 

will be used by Bonneville for trend 

analysis only. According to Bonneville, 

these filings are not reviewed in an 

average system cost review process, and 

do not result in a change to the utility’s 

average system cost. 

35. Bonneville notes that, although 

historically it developed its average 

system cost review procedures as part of 

the ASC methodology consultation 

process, the Commission has previously 

found that it has no jurisdiction over 

these procedures, and has directed 

comments on these matters to 

Bonneville.34 Bonneville, therefore, 

requests that, consistent with this past 

practice, §§ 301.3, 301.4, and 301.7 of 

the regulations established in the 

interim rule be removed. 

Comments 

36. Commenters challenge elements of 

the Bonneville’s process for reviewing a 

utility’s average system cost 

determination, including but not limited 

to the following: (1) Bonneville’s 

decision to require utilities to file 

Appendix 1 annually using updated 

FERC Form 1 data; 35 and (2) 

Bonneville’s failure to commit to 

limiting future Exchange Periods to twoyear periods.36

Commission Determination 

37. The Commission finds that 

commenters are challenging elements of 

Bonneville’s process for reviewing a 

utility’s average system cost 

determination that are beyond the 

Commission’s scope of review. As we 

have explained, our role is a limited 

one—insuring consistency with the 

Northwest Power Act.37 We are not 

otherwise authorized to challenge the 

Administrator’s decisions relating to the 

specifics of the ASC methodology or the 

processes used to develop both that 

methodology and the resulting 

determinations of average system costs. 

Moreover, Bonneville developed the 

amended ASC methodology through a 

stakeholder process with customers. 

The amended ASC methodology 

approved here represents the results of 

that collaboration. To the extent 

Bonneville and its customers find that 

any component of Bonneville’s process 

needs further refinement, we anticipate 

that Bonneville and its customers will 

resolve the issue through further 

collaboration as provided by the statute. 

E. Relationship Between Bonneville’s 

Tiered Rate 

Methdology and ASC Methodology 

38. In its comments, Bonneville states 

that amended § 301.5 contains 

provisions that relate to the interplay 

between its ASC methodology and its 

proposed Tiered Rates methodology. 

According to Bonneville, the Tiered 

Rates methodology implements a new 

tiered rate structure that will establish 

one set of rates (Tier 1) for public 

bodies, cooperatives and Federal 

agencies (preference customers) that 

recovers the costs of Bonneville’s 

current generating system and programs, 

including the Residential Exchange 

Program. Bonneville notes that these 

customers will be limited as to the 

amount of power that can be purchased 

at Tier 1 rates. Bonneville states that 

another set of rates (Tier 2) will be 

established to recover the costs of new 

generating resources. According to 

Bonneville, preference customers will 

be able to purchase power for their 

requirements that remain after 

purchasing up to their maximum MW at 

Tier 1 rates. Bonneville states that its 

Tiered Rates methodology is structured 

to keep separate the costs of resources 

recovered through Tier 1 rates from the 

costs of resources recovered through 

Tier 2 rates. Bonneville states that 

resources whose costs are recovered 

through Tier 2 rates will serve the load 

growth of preference customers. 

39. Bonneville explains that, to 

implement the Tiered Rate 

methodology, it is now offering 

preference customers a new power sales 

agreement, a Regional Dialogue High 

Water Mark Contract, for power sales 

beginning in FY 2012. Bonneville notes 

that, for those preference customers that 

choose to execute this contract, there 

will be certain restrictions on the 

resources that these preference 

customers may exchange with 

Bonneville, identified in amended 

§ 301.5(g). According to Bonneville, 

these restrictions are necessary to 

ensure that the separate ‘‘cost pooling’’ 

concept of tiered rates is maintained. 

Bonneville states that the Tiered Rate 

methodology features in its ASC 

methodology will only affect preference 

customers that execute this type of 

contract. 

40. Bonneville notes that, although 

the Commission does not have 

jurisdiction over its average system cost 

determination for preference customers, 

those provisions of its ASC 

methodology will be used in its review 

of preference customers’ average system 

costs. Bonneville, therefore, requests the 

Commission to retain these provisions 

in its final rule to maintain the 

continuity of its ASC methodology and 

for ease of reference for both Bonneville 

and its preference customers. 

Comments 

41. APAC notes that § 301.5(g) of the 

Commission’s regulations incorporates 

the Tiered Rate methodology and the 

determination of High Water Marks.38

APAC states that Tiered Rate 

methodology is still being finalized. 

APAC argues that, in that proceeding, it 

objected to the legality of the Tiered 

Rate methodology, arguing that it 

exceeded Bonneville’s statutory 


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39See United States Department of Energy— 

Bonneville Power Administration, Docket No. 

EL09–12–000. 

40The language adopted is similar to the language 

used for the prior ASC methodology. See 18 CFR 

301.1(d). 

authority. Also, in that proceeding, 

APAC states that it challenged the 

determination of High Water Marks 

under the Tiered Rate methodology, 

arguing that certain industrial loads 

were not properly characterized. APAC 

requests the Commission not to grant 

approval for the ASC methodology in 

this proceeding until the Tiered Rate 

methodology is finalized by Bonneville 

and reviewed by the Commission. 

Commission Determination 

42. We decline to adopt APAC’s 

request. APAC’s arguments relate to the 

Tiered Rate methodology; that 

methodology is not the subject of this 

rulemaking proceeding. Bonneville’s 

references to the Tiered Rate 

methodology in this rulemaking 

proceeding relate only to the interplay 

between the Tiered Rate methodology 

and the ASC methodology established 

in this final rule. That is, this ASC 

methodology final rule does not revise 

the Tiered Rate methodology. It merely 

specifies how the two methodologies 

will work in conjunction with one 

another. We note, further, that, since 

APAC’s comments were filed in this 

proceeding, Bonneville filed its Tiered 

Rate methodology for Commission 

review.39 To the extent that APAC 

objects to the Tiered Rate methodology, 

those objections are more appropriately 

raised in that proceeding. 

III. Section-By-Section Description of 

Proposed Bonneville Amendments 

43. In its comments on the interim 

rule, Bonneville submits proposed 

revisions and additions that are 

described in more detail below. We 

approve these revisions and additions, 

with minor editorial changes, as 

reflected in the regulatory text adopted 

here. 

A. Section 301.1—Applicability 

44. Bonneville requests the 

Commission to replace the language 

originally approved by the Commission 

for § 301.1 of the interim rule with the 

regulatory language that defined 

applicability prior to the interim rule. 

Bonneville believes that that language is 

more appropriate because its procedures 

for determining an average system cost 

should not be included in the 

Commission’s final rule approving its 

ASC methodology. 

B. Section 301.2—Definitions 

45. Bonneville requests that the 

Commission add several definitions. 

Specifically, Bonneville requests the 

following terms be defined: Accounts; 

Average System Cost delta; Average 

System Cost forecast model; Average 

System Cost review process; Consumerowned Utility; Direct Analysis; 

Escalator; Exchange Load; 

Functionalization; Global Insight; Net 

Requirements; Priority Firm Power; Rate 

Period; Rate Period High Water Mark 

Process (RHWM Process); RHWM 

Exchange Load; RHWM System 

Resources; Tier 1 Priced-Power; Tier 1 

System Resources; and Tiered Rates 

Methodology. Bonneville notes that, in 

addition, it has clarified existing 

definitions and added statutory 

citations. 

C. Section 301.3—Filing Procedures 

46. Bonneville requests the 

Commission to remove the regulatory 

text in § 301.3(a)–(h). Bonneville 

explains that these regulations largely 

describe, in detail, its filing procedures 

during the transitional period (i.e., FY 

2009 and FY 2010–11), its ASC 

methodology review procedure filing 

requirements and instructions to 

exchanging utilities, its filing 

procedures, the utility’s attestation 

responsibilities, and the process of 

determining and curing patently 

deficient filings. Going forward, 

according to Bonneville, a simple 

reference to its procedures will be 

sufficient for the Commission’s 

regulations.40

D. Original § 301.4—Bonneville’s ASC 

Methodology Review Process 

47. Bonneville requests the 

Commission to delete § 301.4 as 

originally promulgated in the interim 

rule because it describes Bonneville’s 

ASC review procedures and processes 

that the Commission does not have 

jurisdiction to review. 

E. New § 301.4—Exchange Period 

Average System Cost Determination 

1. Section 301.4(a)—Escalation to 

Exchange Period 

48. Bonneville requests the 

Commission to revise the regulatory text 

to include the following: (1) Add a 

statement at the beginning of the section 

to explain the objective being met with 

the section; (2) to revise the description 

of the ‘‘escalation codes’’ to clarify the 

codes and the source of data for the 

codes; and (3) incorporate corrections 

made in its errata filing in September 

2008. 

2. Section 301.4(b)—Calculation of Sales 

for Resale and Power Purchases 

49. Bonneville requests the 

Commission to revise the name of this 

subsection to clarify that the purpose of 

the subsection is to describe its ASC 

methodology for calculating the utility’s 

sales for resale and power purchase, and 

to add headers to make it apparent 

which paragraphs apply to long-term/ 

intermediate sales for resale and power 

purchases versus short-term sales for 

resale and power purchases. In addition, 

Bonneville proposes adding additional 

language to this subsection to clarify the 

provisions in this subsection. 

3. Section 301.4(c)—Major Resource 

Additions and Reductions and 

Materiality Thresholds 

50. Bonneville explains that amended 

§ 301.4(c) is designed to calculate 

changes in average system cost when a 

utility obtains new resources or loses an 

existing resource. Bonneville proposes 

that language be added to § 301.4(c)(1) 

to clarify that a major resource addition 

or reduction must meet the criteria in 

§ 301.5(c)(3), and meet the materiality 

test in § 301.4(c)(4). Bonneville also 

proposes added language and 

renumbered paragraphs in § 301.5(c) to 

clarify the existing regulatory text. 

4. Section 301.4(d)—Forecasted 

Contract System Load and Exchange 

Load 

51. Bonneville proposes minor 

revisions to § 301.4(d) and proposes to 

insert a sentence that was in its original 

filing but was left out of the interim rule 

approved by the Commission. 

5. Section 301.4(e)—Load Growth Not 

Met by Major Resource Additions 

52. Bonneville proposes minor textual 

changes to § 301.4(e)(1) and (e)(2). 

Bonneville also proposes to add 

language to § 301.4(e)(3) to provide 

greater detail and clarity regarding how 

surplus power from a major resource 

addition will be treated in Bonneville’s 

average system cost forecast model. 

6. Section 301.4(f)—Changes to Service 

Territory 

53. Bonneville proposes minor 

clarifying corrections throughout 

§ 301.4(f) to make the subsection more 

specific, describing in greater detail that 

the utility must file two Appendix 1s, 

and clarifying that the average system 

cost discussed in this section is the Base 

Period average system cost. 


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47058 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

41Endnote K does not appear in the interim rule. 

Bonneville proposed including Endnote K in its 

September 2008 errata filing. Since the Commission 

is accepting Bonneville’s revised regulatory text, 

further specific action by the Commission is not 

needed. 

42Regulations Implementing the National 

Environmental Policy Act, Order No. 486, FERC 

Stats. & Regs. ¶ 30,783 (1987). 

43 18 CFR 380.4(a)(15). 

44 5 U.S.C. 601–12. 

45 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. 

7. Section 301.4(g)—Average System 

Cost Determination for ConsumerOwned Utilities That Elect To Execute 

Rate Period High Water Mark Contracts 

54. Bonneville proposes to revise 

§ 301.4(g) to use defined terms from its 

Tiered Rates Methodology, to change 

the order of the steps in §§ 301.4(g)(3) 

and (g)(4), and to combine the steps in 

§§ 301.4(g)(3) and (g)(5) into a new step 

in § 301.4(g)(4) to clarify calculation of 

the costs that will be excluded from the 

utility’s average system cost. 

8. Section 301.4(h)—Filing of Appendix 

1 

55. Bonneville proposes minor 

corrections throughout this subsection. 

F. Section 301.5—Changes in Average 

System Cost Methodology 

56. Bonneville proposes minor 

corrections throughout this section. 

G. Original § 301.6—Sample Timeline 

Review Procedures 

57. Bonneville requests the 

Commission to delete § 301.6 of the 

interim rule because the provisions are 

outside the purview of the 

Commission’s review. Bonneville notes, 

however, that it will retain this section 

in its ASC review procedures. 

H. New § 301.6—Appendix 1 

Instructions 

58. Bonneville proposes minor 

corrections to this section. 

I. Section 301.7—Average System Cost 

Methodology Functionalization 

59. Bonneville proposes revisions to 

this section to include the following: (1) 

Title correction; (2) addition of 

references to ‘‘revenues, debits or 

credits’’ throughout the section; (3) 

deletion of a sentence in § 301.9(d)(1) 

and addition of language to clarify that 

Accounts with conservation-related 

costs could be reviewed under a direct 

analysis subject to certain provisions; 

(4) deletion of ambiguous language in 

§ 301.9(d)(2); (5) division of 

§ 301.9(d)(3) into §§ 301.9(d)(3) and 

301.9(d)(4); and (6) addition of a 

reference to ‘‘conservation costs’’ and 

deletion of a reference to ‘‘Transmission 

and/or Distributor/Other’’ in 

redesignated § 301.9(d)(4). 

J. Table 1—Functionalization and 

Escalation Codes 

60. Bonneville proposes to update the 

functionalization codes and make 

additional changes that will make the 

table consistent with § 301.5(b)(1) of the 

ASC methodology. 

K. Appendix 1—ASC Utility Filing 

Template 

61. Bonneville proposes the following 

revisions in Appendix 1: (1) Change the 

title of the template to ‘‘ASC Utility 

Filing Template’’; (2) incorporate errata 

corrections; (3) replace the phrase 

‘‘Residential Purchase Sales Agreement’’ 

with the phrase ‘‘ASC Utility Filing 

Template.’’ 

L. Appendix 1 Endnotes 

62. Bonneville proposes the following 

revisions in Appendix 1 Endnotes: (1) 

Add the phrase ‘‘return on equity 

(ROE);’’ and (2) delete Endnote K.41

M. Chief Financial Officer Attestation 

63. Bonneville notes that the 

Commission did not include this 

attestation in its interim rule. 

Bonneville states that it agrees with the 

Commission’s decision because this 

attestation relates to its average system 

cost review process and not to the 

Commission’s review of the utility’s 

ASC. Bonneville states that it will retain 

this attestation as a component of its 

average system cost review procedures. 

IV. Paperwork Reduction Act 

Statement 

64. A Paperwork Reduction Act 

Statement is not required for this final 

rule because the regulations approve a 

methodology used by a Federal power 

marketing administration, in this case 

Bonneville. 

V. Environmental Analysis 

65. 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.42 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 various statutes 

and regulations including the Northwest 

Power Act.43 The actions taken here fall 

within this categorical exclusion in the 

Commission’s regulations. 

VI. Regulatory Flexibility Act 

66. The Regulatory Flexibility Act of 

1980 (RFA) 44 generally requires a 

description and analysis of the effect 

that a rule will have on small entities or 

a certification that a rule will not have 

a significant economic impact on a 

substantial number of small entities. 

67. The Commission concludes that 

this final rule will not have a significant 

economic impact on a substantial 

number of small entities. Bonneville is 

a Federal power marketing 

administration. And the investor-owned 

utilities which are participating in the 

Residential Exchange Program and 

which, as public utilities under the 

FPA, make ASC-related filings with the 

Commission are not small entities.45

Moreover, the number of public utilities 

participating in the program is not 

substantial; only nine public utilities, 

whose rates are within the 

Commission’s jurisdiction, are 

participating in the program. 

VII. Document Availability 

68. 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 Eastern 

time) at 888 First Street, NE., Room 2A, 

Washington, DC 20426. 

69. 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. 

70. 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 

publicreferenceroom@ferc.gov. 


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VIII. Effective Date 

Given that this final rule establishes 

the methodology that Bonneville Power 

Administration will apply to determine 

average system costs, and thus what 

Bonneville will pay, this final rule 

meets the exception provisions of 5 

U.S.C. 804(3)(A). This final rule is 

effective October 15, 2009. 

List of Subjects in 18 CFR Part 301 

Electric power rates, Electric utilities, 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Kimberly D. Bose, 

Secretary. 

■ In consideration of the foregoing, the 

Commission amends part 301, Title 18, 

Chapter I of the Code of Federal 

Regulations, as follows: 

■ 1. Part 301 is revised 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 Exchange Period Average System 

Cost determination. 

301.5 Changes in Average System Cost 

methodology. 

301.6 Appendix 1 instructions. 

301.7 Average System Cost methodology 

functionalization. 

Table 1 to Part 301—Functionalization and 

Escalation Codes 

Appendix 1 to Part 301—ASC Utility Filing 

Template 

Authority: 16 U.S.C. 839–839h. 

§ 301.1 Applicability. 

The regulations in this part apply to 

the sales of electric power by any Utility 

to the Bonneville Power Administration 

(Bonneville) 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: 

Account(s). The Accounts prescribed 

in the Commission’s Uniform System of 

Accounts in part 101 of this chapter. 

Appendix 1. Appendix 1 is the 

electronic form on which a Utility 

reports its Contract System Cost, 

Contract System Load, and other 

necessary data to Bonneville for the 

calculation of the Utility’s Average 

System Cost. 

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 the quotient obtained by 

dividing Contract System Cost by 

Contract System Load. 16 U.S.C. 

839c(c). 

Average System Cost delta (ASC 

delta). The change in a Utility’s ASC 

during the Exchange Period resulting 

from the inclusion in the Average 

System Cost forecast model of costs, 

loads, revenues, and other information 

related to the commercial operation of a 

major resource addition or reduction 

that was identified in the Utility’s ASC 

filing. 

Average System Cost forecast model 

(ASC forecast model). The model 

Bonneville uses to escalate a Utility’s 

costs, revenues, and other information 

contained in the Appendix 1 to 

calculate the Exchange Period ASC. 

Average System Cost review process 

(ASC review process). The 

administrative proceeding conducted 

before Bonneville under Bonneville’s 

ASC review procedures in which a 

Utility’s ASC is determined. 

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 and 

additional specified 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 

CHWM Contract. 

Commission. Federal Energy 

Regulatory Commission. 

Consumer-owned Utility. A public 

body or cooperative that is eligible to 

purchase preference power from 

Bonneville under section 5(b) of the 

Northwest Power Act. 16 U.S.C. 839c(b). 

Contract System Cost. The Utility’s 

costs for production and transmission 

resources, including power purchases 

and conservation measures, which costs 

are includable in, and subject to, the 

provision of Appendix 1. Under no 

circumstances will Contract System 

Cost include costs excluded from ASC 

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

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

Contract System Load. The total 

regional retail load included in the most 

recently filed FERC Form 1 or, for a 

Consumer-owned Utility, the total retail 

load from the most recent annual 

audited financial statement, as adjusted 

pursuant to the ASC methodology. 

Direct Analysis. An analysis, 

including supporting documentation, 

prepared by the Utility that assigns the 

costs, debits, credits, and revenues in an 

Account to the Production, 

Transmission, and/or Distribution/Other 

functions of the Utility. 

Escalator. A factor used to adjust an 

Account in the Base Period ASC filing 

to the value for the period of the 

Exchange Period ASC. 

Exchange Load. All residential, 

apartment, seasonal dwelling and farm 

electrical loads eligible for the 

Residential Exchange Program under the 

terms of a Utility’s Residential Purchase 

and Sales Agreement. 

Exchange Period(s). The period 

during which a Utility’s Bonnevilleapproved 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, 2008, 

through September 30, 2009. 

Subsequent Exchange Periods will be 

the period of time concurrent with 

Bonneville’s wholesale power rate 

periods beginning October 1 or, if not 

beginning October 1, then beginning on 

the effective date of Bonneville’s 

subsequent wholesale power rate 

periods. 

Exchange Period ASC. The Base 

Period ASC escalated to a year(s) 

consistent with the Exchange Period. 

FERC Form 1. The annual filing 

submitted to the Federal Energy 

Regulatory Commission, required by 18 

CFR 141.1. 

Functionalization. The process of 

assigning a Utility’s costs, debits, 

credits, and revenues in an Account to 

the Production, Transmission, and/or 

Distribution/Other functions of the 

Utility. 

Global Insight. The company that 

provides the escalation factors 

identified in § 301.4(a)(3) that are used 

in the ASC forecasting model, or the 

successor or replacement of that 

company, as determined by Bonneville. 

Jurisdiction. The service territory of 

the Utility within which a particular 

regulatory body has authority to 

approve the Utility’s retail rates. 

Jurisdictions must be within the Pacific 

Northwest region as defined in section 

3(14) of the Northwest Power Act. 16 

U.S.C. 839a(14). 

Labor Ratios. The ratios that 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 FERC Form 1. For 

Consumer-owned Utilities, comparable 


srobinson on DSKHWCL6B1PROD with RULES
47060 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

data will be utilized based on the costof-service study used as the basis for 

retail rates at the time of review. 

Net Requirements. The amount of 

Federal power that a Consumer-owned 

Utility is entitled to purchase from 

Bonneville under section 5(b) of the 

Northwest Power Act. 16 U.S.C. 839c(b). 

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 Purchase 

and Sales Agreements with its Regional 

Power Sales Customers. 16 U.S.C. 

839a(13). 

Priority Firm Power. Priority Firm 

Power is electric power (capacity and 

energy) that Bonneville will make 

continuously available for direct 

consumption or resale to public bodies, 

cooperatives, and Federal Agencies 

(under the Priority Firm Preference rate) 

and to Utilities participating in the 

Residential Exchange Program (under 

the Priority Firm Exchange rate). 

Utilities participating in the Residential 

Exchange Program under section 5(c) of 

the Northwest Power Act may purchase 

Priority Firm Power under their 

Residential Purchase and Sales 

Agreements with Bonneville. Priority 

Firm Power is not available to serve 

New Large Single Loads. Deliveries of 

Priority Firm Power may be reduced or 

interrupted as permitted by the terms of 

the Utilities’ power sales contracts and/ 

or Residential Purchase and Sales 

Agreements with Bonneville. 

Public Purpose Charge. Any charge 

based on a Utility’s total retail sales in 

a Jurisdiction that is provided to 

independent entities or agencies of state 

and local governments for the purpose 

of funding within the Utility’s service 

territory one or both of the following: 

(a) Conservation programs in lieu of 

Utility conservation programs; or 

(b) Acquisition of renewable 

resources. 

Rate Period. The period during which 

Bonneville’s wholesale power rates are 

effective. The period is coincident with 

the Exchange Period. 

Rate Period High Water Mark 

(RHWM). The amount used to define 

each customer’s eligibility to purchase 

Tier 1 Priced Power for the relevant Rate 

Period, subject to the customer’s Net 

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 Bonneville wholesale 

power rate case. 

Rate Period High Water Mark Process 

(RHWM Process). The process or 

processes where each eligible 

Consumer-owned Utility RHWM is 

determined. 

Regional Power Sales Customer. Any 

entity that contracts directly with 

Bonneville for the purchase of power 

under sections 5(b) (16 U.S.C. 839c(b)), 

5(c) (16 U.S.C. 839c(c)), or 5(d) (16 

U.S.C. 839c(d)) of the Northwest Power 

Act for delivery in the Pacific Northwest 

region as defined by section 3(14) of the 

Northwest Power Act. 16 U.S.C. 

839a(14). 

Residential Purchase and Sales 

Agreement. The contract under section 

5(c) of the Northwest Power Act 

between Bonneville and a Utility that 

defines and implements the power 

purchase and sale under the Residential 

Exchange Program. 

Review Period. The period of time 

during which a Utility’s Appendix 1 is 

under review by Bonneville. The 

Review Period begins on or about 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. 

Regulatory Body. A state commission, 

Consumer-owned Utility governing 

body, or other entity authorized to 

establish retail electric rates in a 

Jurisdiction. 

RHWM Exchange Load. The Exchange 

Load as determined in section 20 of the 

Residential Purchase and Sales 

Agreement. 

RHWM System Resources. The Rate 

Period High Water Mark (RHWM) as 

calculated in section 4.2.1 of the Tiered 

Rates Methodology plus the resource 

amounts used in calculating a 

customer’s Contract High Water Mark 

(CHWM). 

Tier 1 Priced-Power. Priority Firm 

Power as defined in Bonneville’s Tiered 

Rates Methodology. 

Tier 1 System Resources. Resources as 

defined in Bonneville’s Tiered Rates 

Methodology. 

Tiered Rates Methodology. The longterm methodology established by 

Bonneville for the determination of 

tiered wholesale power rates. 

Utility. A Regional Power Sales 

Customer that has executed a 

Residential Purchase and Sales 

Agreement. 

§ 301.3 Filing procedures. 

(a) Bonneville’s ASC review 

procedures. The procedures established 

by Bonneville’s Administrator provide 

the filing requirements for all Utilities 

that file an Appendix 1 with Bonneville. 

Utilities must file Appendix 1s, ASC 

forecast models, and other required 

documents with Bonneville in 

compliance with Bonneville’s ASC 

review procedures. 

(b) Exchange Period. The Exchange 

Period will be equal to the term of 

Bonneville’s Rate Period. ASCs will 

change during the Exchange Period only 

for the reasons provided in § 301.4. 

§ 301.4 Exchange Period Average System 

Cost determination. 

(a) Escalation to Exchange Period. 

(1) This section describes the method 

Bonneville will use to escalate the Base 

Period ASC to and through the 

Exchange Period to calculate the 

Exchange Period ASC. 

(2) Bonneville will escalate the 

Bonneville-approved Base Period ASC 

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. 

(3) For purposes of the escalation 

referenced in paragraph (a)(2) of this 

section, Bonneville will use the 

following codes in the ASC forecast 

model to calculate the Exchange Period 

ASCs: 

(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) DOPS—Distribution Operations 

(x) HMN—Hydro Maintenance. 

(xi) HOPS—Hydro Operations. 

(xii) INF—Inflation. 

(xiii) NATGAS—Natural Gas. 

(xiv) NFUEL—Nuclear Fuel. 

(xv) NMN—Nuclear Maintenance. 

(xvi) NOPS—Nuclear Operations. 

(xvii) OMN—Other Production 

Maintenance. 

(xviii) OOPS—Other Production 

Operations. 

(xix) SNM—Steam Maintenance. 

(xx) SOPS—Steam Operations. 

(xxi) TMN—Transmission 

Maintenance. 

(xxii) TOPS—Transmission 

Operations. 

(xxiii) WAGES—Wages. 

(4) Table 1 identifies which codes 

from paragraph (a)(3) of this section 

apply to the line items and associated 

FERC Accounts in the Appendix 1. 

Bonneville will use Global Insight as the 

source of data for the escalation codes 

indentified in paragraph (a)(3) of this 

section, except for the NATGAS and 

CONSTANT codes. For the NATGAS 

code identified in paragraph (a)(3)(xiii) 


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of this section, Bonneville will calculate 

the escalation rate using Bonneville’s 

most current forecast of natural gas 

prices. The code CONSTANT in 

paragraph (a)(3)(iv) of this section 

indicates that no escalation to the 

Account will be made. 

(5) Bonneville will base the costs of 

power products purchased from 

Bonneville on Bonneville’s forecast of 

prices for its products. 

(6) Bonneville will escalate the Public 

Purpose Charge forward to the midpoint 

of the Exchange Period by the same rate 

of growth as total Contract System Load. 

(7) If any of the escalators specified in 

paragraph (a) of this section are no 

longer available, Bonneville will 

designate a replacement source of such 

escalator(s) that, as near as possible, 

replicates the results produced by the 

prior escalator. If a replacement source 

is not available, Bonneville will use the 

INF escalation code identified in 

paragraph (a)(3)(xii) of this section as 

the replacement escalator. 

(b) Calculation of sales for resale and 

power purchases— 

(1) Long-term and intermediate-term 

sales for resale and power purchases. 

Bonneville will use the INF escalation 

code identified in paragraph (a)(3)(xii) 

of this section to escalate long-term and 

intermediate-term (as defined by the 

Commission) firm purchased power 

costs and long-term and intermediateterm sales for resale revenues. 

(2) Short-term sales for resale and 

power purchases. 

(i) The short-term purchases and 

short-term 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 to use 

a utility-specific forecast for the price of 

purchased power and for the price of 

sales for resale in order to value 

purchased power expenses and sales for 

resale revenue to be included in the 

Exchange Period ASC. 

(ii) Bonneville will use the following 

method to determine separate market 

prices to forecast short-term purchased 

power expenses and sales for resale 

revenues to calculate Exchange Period 

ASCs: 

(A) 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). 

(B) The midpoint between the 

Utility’s average short-term purchased 

power price and the average short-term 

sales for resale price will be calculated 

for each of the years in paragraph 

(b)(2)(ii)(A) of this section. 

(C) The percentage spread around the 

Utility’s midpoint between the average 

short-term purchase power price and 

short-term sales for resale price will be 

calculated for each of the years 

identified in paragraph (b)(2)(ii)(A) of 

this section. 

(D) 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: 

(1) Three (3) times Base Period 

spread. 

(2) Two (2) times (Base Period minus 

1) spread. 

(3) One (1) time (Base Period minus 

2) spread. 

(E) The Base Period midpoint 

calculated in paragraph (b)(2)(ii)(B) of 

this section will be escalated at the same 

rate as Bonneville’s electric market price 

forecast. 

(F) The weighted average spread 

calculated in paragraph (b)(2)(ii)(D) of 

this section will be applied to the 

escalated midpoint price calculated in 

paragraph (b)(2)(ii)(E) of this section to 

determine the purchased power price 

and sales for resale price to value 

purchased power expenses and sales for 

resale revenues to be included in the 

Exchange Period ASC. 

(iii) The method described in 

paragraph (b)(2)(ii) of this section will 

be used to forecast the electric market 

price for power purchases needed to 

meet load growth not met by major 

resource additions, and to forecast the 

electric market price for any additional 

surplus power sales resulting from 

major resource additions. 

(c) Major resource additions and 

reductions and materiality thresholds. 

(1) During the Exchange Period, 

Bonneville will allow changes to a 

Utility’s ASC to account for major 

resource additions or reductions that are 

used to meet a Utility’s retail load. 

These changes, however, must meet the 

requirements of paragraph (c)(3) of this 

section and the materiality threshold 

described in paragraph (c)(4) of this 

section in order for Bonneville to allow 

an ASC to change. The ASC reflecting 

the major resource addition or reduction 

will be determined by Bonneville in the 

ASC review process during the Review 

Period. 

(2) For major resource additions, the 

change to ASC will become effective 

when the resource begins commercial 

operation, or power is received under 

the purchased power contract. For major 

resource reductions, the change to ASC 

will become effective when the resource 

is sold, retired, or transferred. 

(3) A major resource addition or 

reduction must be related to one or 

more of the following categories to be 

eligible for consideration as a major 

resource: 

(i) Production or generating resource 

investments; 

(ii) Transmission investments; 

(iii) Long-term generating contracts; 

(iv) Pollution control and 

environmental compliance investments 

relating to generating resources; 

(v) Long-term transmission contracts; 

(vi) Hydroelectric relicensing costs 

and fees; and 

(vii) Plant rehabilitation investments. 

(4) Major resource additions or 

reductions that meet the criteria 

identified in paragraph (c)(3) of this 

section will be allowed to change a 

Utility’s ASC within an Exchange 

Period provided that the major resource 

addition or reduction results in a 2.5 

percent or greater change in a Utility’s 

Base Period ASC. Bonneville will allow 

a Utility to submit stacks of individual 

resources that, when combined, meet 

the 2.5 percent or greater materiality 

threshold, provided, however, that each 

resource in the stack must result in a 

change to the Utility’s Base Period ASC 

of 0.5 percent or more. 

(5) At the time the Utility submits its 

Appendix 1 filing, the Utility will 

provide its forecast of major resource 

additions or reductions and all 

associated costs. The forecast will cover 

the period from the end of the Base 

Period to the end of the Exchange 

Period. 

(6) Bonneville will calculate new 

transmission wheeling revenues 

associated with new transmission 

investment using the following formula: 

TTWR = WR (before additions) * [(NTP 

(before additions) + NTA)/NTP 

(before additions)] 

Where: 

TTWR = total transmission wheeling 

revenues 

WR (before additions) = wheeling revenues 

(before additions) 

NTA = new transmission additions 

NTP (before additions) = Net Transmission 

Plant (before additions) 

(7) The forecast of major resource 

additions or reduction costs to be 

included in the Utility’s Exchange 

Period ASC will be reviewed by 

Bonneville in the ASC review process 

that is conducted during the Review 

Period. 

(8) All major 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. 

(9) For each major resource addition 

or reduction that is forecasted to occur 

during the Exchange Period, Bonneville 


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47062 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

will calculate the difference in ASC 

between the ASC without the major 

resource addition or reduction and the 

ASC with the major resource addition or 

reduction (ASC delta) at the midpoint of 

the Exchange Period. 

(10) Once the major resource addition 

or reduction becomes effective, as 

determined by paragraph (c)(2) of this 

section, Bonneville will add the ASC 

delta to the Utility’s existing ASC to 

determine its new ASC. 

(11) For purposes of calculating ratios 

with Distribution Plant, Bonneville will 

escalate the Base Period average perMWh 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. 

(12) Bonneville will escalate the cost 

of General Plant, Accounts 389 through 

399.1, forward to the midpoint of the 

Exchange Period by calculating the ratio 

of each Account’s value in the Base 

Period to the sum of Production, 

Transmission, and Distribution plant 

values in the Base Period, and then 

multiplying the Base Period ratio times 

the forecasted value for Production, 

Transmission, and Distribution plant. 

(13) Bonneville will issue procedural 

rules to ensure the confidentiality of 

information provided by Utilities 

regarding any major resource additions 

or reductions 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, load growth 

will be assumed to be met with 

purchases in the wholesale market, as 

described in paragraph (e) of this 

section. If the Utility fails to supply 

confidential resource data, it loses the 

difference between the cost of the 

resource and the price of electricity in 

the wholesale market. 

(d) Forecasted Contract System Load 

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 analysis as described in 

Endnote e of Appendix 1, with their 

Appendix 1 filings. The load forecast for 

Contract System Load and Exchange 

Load will start with the Base Period and 

extend through four (4) years after the 

Exchange Period. The load forecast for 

Contract System Load and Exchange 

Load will be provided on a monthly 

basis for the Exchange Period. 

(e) Load growth not met by major 

resource additions. All forecast load 

growth not met by major 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 electric market 

purchases priced at the Utility’s forecast 

short-term purchased power price as 

determined in paragraph (b) of this 

section unless the Utility forecasts major 

resource additions. 

(2) In the event of major resource 

additions, forecast Load Growth will be 

met by the major resource(s). If the 

major resource is less than total forecast 

load growth, the unmet Load Growth 

will be met with electric market 

purchases priced at the Utility’s forecast 

short-term purchased power price. 

(3) In the event the power provided by 

a major resource exceeds the Utility’s 

forecast Load Growth, the excess power 

will be used to reduce the Utility’s 

short-term purchases. If short-term 

power purchases are reduced to zero, 

any remaining power will be sold as 

surplus power at the short-term 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 existing service territory, 

and the gain or loss of that territory 

results in a 2.5 percent or greater change 

to the Utility’s Base Period ASC, the 

Utility must file two Appendix 1 filings 

with Bonneville as follows: 

(1) First, a Base Period ASC that does 

not reflect the acquisition or loss of 

service territory; and 

(2) Second, a Base Period ASC that 

incorporates the following changes: 

(i) A forecast of the increase or 

reduction in Contract System Load 

associated with the acquisition or 

reduction in service territory. 

(ii) A forecast of the increase or 

reduction in Contract System Cost 

associated with the acquisition or 

reduction of the service territory. 

(iii) A forecast of capital and 

operating cost increases or reductions 

associated with the change in service 

territory. 

(iv) A forecast of the changes in 

purchased power expenses, sales for 

resale revenues, and other debits or 

credits based on the changes in the 

service territory. 

(3) 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 Consumerowned Utilities that elect to execute 

Regional Dialogue High Water Mark 

contracts. For Consumer-owned 

Utilities that elect to execute Regional 

Dialogue CHWM contracts, Bonneville 

will use the following approach: 

(1) Use the RHWM System Resources 

as determined in the Tiered Rates 

Methodology (TRM) process. 

(2) Determine the RHWM Exchange 

Load. 

(3) Calculate the Utility’s Contract 

System Cost as described in the ASC 

Methodology. 

(4) Determine the fully allocated cost 

of resources used to meet Contract 

System Load that is not met by: 

(i) The lesser of the Utility’s RHWM 

or Forecast New Requirement, plus 

(ii) Existing Resources for CHWM (as 

defined in the Tiered Rates 

Methodology). 

(5) RHWM Contract System Cost = 

Contract System Cost minus fully 

allocated cost of resources (from 

paragraph (g)(4) of this section). 

(6) RHWM Average System Cost = 

RHWM Contract System Cost (from 

paragraph (g)(5) of this section)/RHWM 

System Resource (from paragraph (g)(1) 

of this section). 

(h) Filing of Appendix 1. Utilities 

must file an Appendix 1, including ASC 

information, by June 1 of each year, as 

required in § 301.3, 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. 

§ 301.5 Changes 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, 

Bonneville’s Administrator may file the 

new ASC methodology with the 

Commission. 

(b) The Administrator will not initiate 

any consultation process until one year 

of experience has been gained under the 

then-existing ASC methodology, that is, 

one year after the then-existing ASC 

methodology is adopted by Bonneville 

and approved by the Commission, 

through interim or final approval, 

whichever occurs first. 

(c) The Administrator may, from time 

to time, issue interpretations of the ASC 

methodology. The Administrator also 


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Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 47063 

may modify the functionalization code 

of any Account to comply with the 

limitations identified in sections 

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

Act or to conform to Commission 

revisions to the Uniform System of 

Accounts. 

§ 301.6 Appendix 1 instructions. 

(a) Appendix 1 is the form on which 

a Utility reports its Contract System 

Cost, Contract System Load, 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 with the 

provisions of the endnotes following the 

schedules. 

(b) Appendix 1 filings must be 

accompanied by an attestation statement 

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 FERC 

Form 1 filings 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 Cost. In addition, the 

cost-of-service report must be reviewed 

by an independent accounting or 

consulting firm, and must be 

accompanied by a report from that 

independent accounting or consulting 

firm that outlines the review work that 

was performed in preparing the cost-ofservice report along with an assurance 

statement that the information 

contained in the cost-of-service report is 

presented fairly in all material respects. 

(e) The Appendix 1 template is 

available electronically at http:// 

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

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 

support costs and loads, including 

details of allocation and 

functionalization. All references to the 

Commission’s Accounts are to the 

Commission’s Uniform System of 

Accounts, 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 the 

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 a 

Jurisdiction within the Pacific 

Northwest and within Jurisdictions 

outside the Pacific Northwest 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 filing must include details of 

the allocation. 

(2) The allocation must exclude all 

costs of additional resources used to 

meet loads outside the Pacific 

Northwest, 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. 

§ 301.7 Average System Cost 

methodology functionalization. 

(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) Functionalization codes. 

(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 requirements. 

(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 method 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, 

revenues, debits or credits 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, 

revenues, debits and credits to the 

Production, Transmission, and/or 

Distribution/Other function of the 

Utility. The only exception to this 

requirement is for Accounts that include 

conservation-related costs. Subject to 

the provisions of paragraph (d)(4) of this 

section, a Utility may conduct a Direct 

Analysis on any Account that contains 

conservation-related costs. The Direct 

Analysis performed by a Utility is 

subject to Bonneville review and 

approval. 

(2) Bonneville will not allow a Utility 

to use a combination of Direct Analysis 

and a prescribed functionalization 

method for the same Account. The 

Utility can develop and use a 

functionalization ratio, or use a 


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47064 Federal Register / Vol. 74, No. 177 / Tuesday, September 15, 2009 / Rules and Regulations 

prescribed functionalization method, if 

the Utility, through Direct Analysis, can 

justify how the ratio reflects the 

functional nature of the costs, revenues, 

debits, or credits included in any 

Account. 

(3) A Utility that wishes to include 

advertising and promotion costs related 

to conservation will use Direct Analysis. 

(4) If a Utility records conservation 

costs in an Account that is 

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 

Account does not authorize the Utility 

to perform a Direct Analysis on the 

entire Account. This option allows a 

Utility to assign conservation costs in 

the specified Account to Production 

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 

assign 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. 

Table 1 to Part 301—Functionalization 

and Escalation Codes 

BILLING CODE 6717–01–P 


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Appendix 1 to Part 301—ASC Utility 

Filing Template 


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Note: The following Appendix will not be 

published in the Code of Federal 

Regulations. 

Appendix—List of Commenters 

Association of Public Agency Customers 

(APAC) 

Avista Corporation (Avista) 

Idaho Power Company (Idaho Power) 

Idaho Public Utilities Commission (Idaho 

PUC) 

PacifiCorp 

Pacific Northwest Investor-Owned Utilities 

(IOU) 

Portland General Electric Company (Portland 

General) 

Public Utility District No. 1 of Clark County, 

Washington and Public Utility District No. 

1 of Grays Harbor County, Washington, 

Public Utility District No. 1 of Snohomish 

County, Washington (Districts) 

Puget Sound Energy, Inc. (Puget Sound) 

Washington Utilities and Transportation 

Commission (WUTC) 

[FR Doc. E9–21946 Filed 9–14–09; 8:45 am] 

BILLING CODE 6717–01–C 

DEPARTMENT OF JUSTICE 

28 CFR Part 0 

[Docket No. AG Order No. 3108–2009] 

The Attorney General’s Advisory 

Committee of United States Attorneys 

AGENCY: Department of Justice. 

ACTION: Final rule. 

SUMMARY: This rule amends the 

Department of Justice regulation 

concerning the Attorney General’s 

Advisory Committee of United States 

Attorneys. The amendments will 

provide the Attorney General greater 

flexibility in determining the size of the 

Committee, and will provide that the 

Attorney General will select the 

Committee’s leadership. 

DATES: Effective Date: September 15, 

2009. 

FOR FURTHER INFORMATION CONTACT: 

Norman Wong, Deputy Director and 

Counsel to the Director, Executive 

Office for United States Attorneys, 

Department of Justice, 950 Pennsylvania 

Avenue, Washington, DC 20530 (202) 

514–2121. 

SUPPLEMENTARY INFORMATION: This 

regulation recognizes that the United 

States Attorneys, as Presidential 

appointees having responsibilities 

mandated by Congress (28 U.S.C. 547), 

should be afforded an appropriate and 

formal means for contributing to the 

development of Department of Justice 

policies and procedures. The Attorney 

General’s Advisory Committee of United 

States Attorneys (‘‘Committee’’) aids the 

improvement of communication 

between federal and state law 

enforcement officials, the promotion of 

greater consistency in the application of 

legal standards, and the improvement of 

the criminal justice system at all levels 

of government. Under the existing 

regulation, the Committee is composed 

of fifteen members designated by the 

Attorney General, and the Committee is 

charged with selecting its leadership. 

Under the revised regulation, the 

Attorney General will determine the 

number of Committee members and will 

select from the membership a 

chairperson and vice-chairperson. The 

United States Attorney for the District of 

Columbia will serve as an ex officio 

member. 

Administrative Procedure Act 

This rule is a rule of agency 

organization and procedure, and relates 

to the internal management of the 

Department of Justice. It is therefore 

exempt from the requirements of notice 

and comments and a delayed effective 

date. 5 U.S.C. 553(b), (d). 

Regulatory Flexibility Act 

The Attorney General, in accordance 

with the Regulatory Flexibility Act (5 

U.S.C. 605(b), has reviewed this 

regulation and by approving it certifies 

that this regulation will not have a 

significant economic impact on a 

substantial number of small entities 

because it pertains to personnel and 

administrative matters affecting the 

Department. Further, a Regulatory 

Flexibility Analysis was not required to 

be prepared for this final rule since the 

Department was not required to publish 

a general notice of proposed rulemaking 

for this matter. 


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