Document ID: FERC-2009-1392-0001
Agency: ferc
Document Type: Rule
Title: Sales of Electric Power to the Bonneville Power Administration; Revisions to Average System Cost Methodology
Posted Date: 2009-09-15T04:00Z

[Federal Register: September 15, 2009 (Volume 74, Number 177)]
[Rules and Regulations]               
[Page 47052-47096]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15se09-4]                         

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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.

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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\
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    \1\ 16 U.S.C. 839c(c).
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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.
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    \2\ 16 U.S.C. 839c(c)(1).
    \3\ This rate is generally a lower rate.
    \4\ See 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)).
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    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.
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    \5\ 16 U.S.C. 839c(c)(7).
    \6\ 16 U.S.C. 839c(c)(7)(A)-(C).
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    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\
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    \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).
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    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\
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    \8\ 16 U.S.C. 824, 824d, 824e.
    \9\ Order No. 400, FERC Stats. & Regs. ] 30,601 at 31,161-62.
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    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

[[Page 47053]]

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.
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    \10\ See 18 CFR Part 301.
    \11\ The 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).
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    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\
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    \12\ Comments 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.
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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 
Sec. Sec.  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 Sec.  
301.5); and (3) provisions relating to Bonneville's average system 
review process and procedures (amended Sec. Sec.  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 consumer-owned 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 investor-owned utilities can include the 
costs of all non-federal resources and their entire retail loads, and 
the consumer-owned 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.
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    \13\ For 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, consumer-owned 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.
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    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

[[Page 47054]]

Commission to reject use of the deemer mechanism.
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    \14\ A 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.
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Bonneville's Answer
    16. Bonneville argues that the Districts mischaracterize the ASC 
methodology as applied to consumer-owned 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.
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    \16\ The 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.
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    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.
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    \17\ See 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'').
    \18\ See 16 U.S.C. 839c(c)(1), (7).
    \19\ See 16 U.S.C. 839c(c)(7).
    \20\ See 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).
    \21\ See 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.
    \22\ See 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).
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    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 Sec. Sec.  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 consumer-owned 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 Sec.  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 Sec.  301.9 and Table 1 of 
Bonneville's ASC

[[Page 47055]]

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.
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    \23\ The 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.
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    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 Sec.  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 mid-point of Bonneville's rate period.\24\
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    \24\ See, e.g., Avista comments at 4; Idaho Power comments at 5.
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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.
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    \25\ See supra notes 19-22 and accompanying text.
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C. Exchange Period Average System Cost Determination

    28. According to Bonneville, amended Sec. Sec.  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 Sec.  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

[[Page 47056]]

execute Regional Dialogue High Water Mark contracts.\32\
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    \26\ See, e.g., APAC comments at 1-2.
    \27\ See, e.g., WUTC comments at 6; Avista comments at 14-16; 
Idaho Power at 3-6.
    \28\ See, e.g., WUTC comments at 7; Avista comments at 11; Idaho 
Power comments at 10.
    \29\ See, e.g., Avista comments at 4-5; Idaho Power at 6-7.
    \30\ See, e.g., Avista comments at 8; Portland General comments 
at 9; Idaho Power comments at 10.
    \31\ Avista comments at 9; Idaho Power comments at 11.
    \32\ See, e.g., Avista comments at 12; Idaho Power comments at 
14.
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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.
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    \33\ See supra notes 19-22 and accompanying text.
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D. Bonneville's Review of a Utility's Average System Cost Determination

    34. Amended Sec. Sec.  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, Sec. Sec.  301.3, 301.4, and 301.7 
of the regulations established in the interim rule be removed.
---------------------------------------------------------------------------

    \34\ See Order No. 337, FERC Stats. & Regs. at ] 30,506 at 
30,738.
---------------------------------------------------------------------------

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 two-year periods.\36\
---------------------------------------------------------------------------

    \35\ See, e.g., Avista comments at 5; Idaho Power comments at 7.
    \36\ See, e.g., Avista comments at 7; Idaho Power comments at 9.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \37\ See supra notes 19-22 and accompanying text; accord Order 
No. 337, FERC Stats. & Regs. ] 30,506 at 30,738.
---------------------------------------------------------------------------

E. Relationship Between Bonneville's Tiered Rate

Methdology and ASC Methodology
    38. In its comments, Bonneville states that amended Sec.  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 Sec.  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 Sec.  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

[[Page 47057]]

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.
---------------------------------------------------------------------------

    \38\ See APAC comments at 2.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \39\ See United States Department of Energy--Bonneville Power 
Administration, Docket No. EL09-12-000.
---------------------------------------------------------------------------

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 Sec.  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; Consumer-owned 
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 Sec.  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\
---------------------------------------------------------------------------

    \40\ The language adopted is similar to the language used for 
the prior ASC methodology. See 18 CFR 301.1(d).
---------------------------------------------------------------------------

D. Original Sec.  301.4--Bonneville's ASC Methodology Review Process

    47. Bonneville requests the Commission to delete Sec.  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 Sec.  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 Sec.  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 Sec.  301.4(c)(1) to clarify that a major resource 
addition or reduction must meet the criteria in Sec.  301.5(c)(3), and 
meet the materiality test in Sec.  301.4(c)(4). Bonneville also 
proposes added language and renumbered paragraphs in Sec.  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 Sec.  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 Sec.  301.4(e)(1) 
and (e)(2). Bonneville also proposes to add language to Sec.  
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 
Sec.  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.

[[Page 47058]]

7. Section 301.4(g)--Average System Cost Determination for Consumer-
Owned Utilities That Elect To Execute Rate Period High Water Mark 
Contracts
    54. Bonneville proposes to revise Sec.  301.4(g) to use defined 
terms from its Tiered Rates Methodology, to change the order of the 
steps in Sec. Sec.  301.4(g)(3) and (g)(4), and to combine the steps in 
Sec. Sec.  301.4(g)(3) and (g)(5) into a new step in Sec.  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 Sec.  301.6--Sample Timeline Review Procedures

    57. Bonneville requests the Commission to delete Sec.  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 Sec.  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 Sec.  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 Sec.  301.9(d)(2); (5) division of Sec.  
301.9(d)(3) into Sec. Sec.  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 
Sec.  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 Sec.  
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\
---------------------------------------------------------------------------

    \41\ Endnote 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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \42\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \43\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \44\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.

[[Page 47059]]

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.

0
In consideration of the foregoing, the Commission amends part 301, 
Title 18, Chapter I of the Code of Federal Regulations, as follows:
0
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.

Sec.  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).

Sec.  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 Bonneville-
approved ASC is effective for the calculation of the Utility's 
Residential Exchange Program benefits. The initial Exchange Period 
under this ASC methodology is from October 1, 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 Sec.  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

[[Page 47060]]

data will be utilized based on the cost-of-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 long-term 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.

Sec.  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 Sec.  301.4.

Sec.  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)

[[Page 47061]]

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 intermediate-term 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

[[Page 47062]]

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 per-MWh cost of 
Distribution Plant forward to the midpoint of the Exchange Period, and 
use the escalated average cost to determine the distribution-related 
cost of meeting load growth since the Base Period.
    (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 Consumer-owned 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 Sec.  
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.

Sec.  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 
three-quarters 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

[[Page 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.

Sec.  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-of-service 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.

Sec.  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

[[Page 47064]]

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