[Federal Register: September 15, 2009 (Volume 74, Number 177)]
[Rules and Regulations]
[Page 47052-47096]
[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<EMAIL_ADDRESS>Julia A. Lake (Legal Information), Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426, Phone: 202-
502-8370, e-mail<EMAIL_ADDRESS>
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

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

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

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

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

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.

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
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>

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

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)

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

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

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

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

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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