Proposed Methodology for Determining the Average System Cost of Resources for Electric Utilities Participating in the Residential Exchange Program Established by Section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act, 7270-7279 [E8-2258]
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Federal Register / Vol. 73, No. 26 / Thursday, February 7, 2008 / Notices
reinstatement; (2) Title; (3) Summary of
the collection; (4) Description of the
need for, and proposed use of, the
information; (5) Respondents and
frequency of collection; and (6)
Reporting and/or Recordkeeping
burden. OMB invites public comment.
The Department of Education is
especially interested in public comment
addressing the following issues: (1) Is
this collection necessary to the proper
functions of the Department; (2) will
this information be processed and used
in a timely manner; (3) is the estimate
of burden accurate; (4) how might the
Department enhance the quality, utility,
and clarity of the information to be
collected; and (5) how might the
Department minimize the burden of this
collection on the respondents, including
through the use of information
technology.
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Dated: February 4, 2008.
Angela C. Arrington,
IC Clearance Official, Regulatory Information
Management Services, Office of Management.
Federal Student Aid
Type of Review: Revision.
Title: Fiscal Operations Report for
2007–2008 and Application to
Participate for 2009–2010 (FISAP) and
Reallocation Form E40–4P.
Frequency: Annually.
Affected Public: Not-for-profit
institutions (primary), Businesses or
other for-profit, Federal Government,
State, Local, or Tribal Gov’t, SEAs or
LEAs.
Reporting and Recordkeeping Hour
Burden:
Responses: 5,798.
Burden Hours: 27,935.
Abstract: This application data will be
used to compute the amount of funds
needed by each school for the 2009–
2010 award year. The Fiscal Operations
Report data will be used to assess
program effectiveness, account for funds
expended during the 2006–2007 award
year, and as part of the school funding
process. The Reallocation Form is part
of the FISAP on the Web. Schools will
use it in the summer to return
unexpended funds for 2006–2007 and
request supplemental FWS funds for
2008–2009.
Requests for copies of the proposed
information collection request may be
accessed from https://edicsweb.ed.gov,
by selecting the ‘‘Browse Pending
Collections’’ link and by clicking on
link number 3581. When you access the
information collection, click on
‘‘Download Attachments’’ to view.
Written requests for information should
be addressed to U.S. Department of
Education, 400 Maryland Avenue, SW.,
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LBJ, Washington, DC 20202–4537.
Requests may also be electronically
mailed to ICDocketMgr@ed.gov or faxed
to 202–401–0920. Please specify the
complete title of the information
collection when making your request.
Comments regarding burden and/or
the collection activity requirements
should be electronically mailed to
ICDocketMgr@ed.gov. Individuals who
use a telecommunications device for the
deaf (TDD) may call the Federal
Information Relay Service (FIRS) at
1–800–877–8339.
[FR Doc. E8–2259 Filed 2–6–08; 8:45 am]
BILLING CODE 4000–01–P
ELECTION ASSISTANCE COMMISSION
Sunshine Act Meeting Notice
United States Election
Assistance Commission (EAC).
ACTION: Notice of Public Meeting
Roundtable Discussion.
AGENCY:
DATE & TIME: Friday, February 29, 2008,
9 a.m.–2 p.m. (EST).
PLACE: United State Election Assistance
Commission, 1225 New York Ave., NW.,
Suite 150, Washington, DC 20005.
Agenda
The Commission will host a voting
systems manufacturer roundtable
discussion regarding the Technical
Guidelines Development Committee’s
(TGDC) recommended voluntary voting
system guidelines (VVSG). The
discussion will be focused upon the
following topics: (1) The dominant
business model for voting system
manufacturers and their role as
innovators; (2) How to evaluate
innovative systems, for which there are
no standards for purposes of
certification; (3) The value and risks
associated with Open Ended
Vulnerability Testing; (4) The processes
associated with testing to the VVSG and
possible modifications; (5) Whether the
recommend TGDC standards create
appropriate functional standards that
promote innovation; (6) The cost
implications of the proposed VVSG; (7)
Development of systems to the proposed
VVSG and possible time frames.
This meeting will be open to the
public.
PERSON TO CONTACT FOR INFORMATION:
Matthew Masterson, Telephone: (202)
566–3100.
Thomas R. Wilkey,
Executive Director, U.S. Election Assistance
Commission.
[FR Doc. 08–565 Filed 2–5–08; 10:57 am]
BILLING CODE 6820–KF–M
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DEPARTMENT OF ENERGY
Bonneville Power Administration
Proposed Methodology for
Determining the Average System Cost
of Resources for Electric Utilities
Participating in the Residential
Exchange Program Established by
Section 5(c) of the Pacific Northwest
Electric Power Planning and
Conservation Act
Bonneville Power
Administration (BPA), DOE.
ACTION: Notice; request for comments
(BPA File No.: ASCM–08).
AGENCY:
SUMMARY: Bonneville Power
Administration (BPA) proposes a
revised methodology for determining
the average system cost (ASC) of
resources for regional electric utilities
that participate in the Residential
Exchange Program (REP) authorized by
section 5(c) of the Pacific Northwest
Electric Power Planning and
Conservation Act (Northwest Power
Act). The ASC methodology is used in
the determination of monetary benefits
paid by BPA to utilities participating in
the REP. The Northwest Power Act
authorizes the BPA Administrator to
determine utilities’ ASCs based on a
methodology developed by BPA in
consultation with the Northwest Power
and Conservation Council, BPA
customers and state regulatory agencies
in the Pacific Northwest. The existing
methodology was adopted by BPA and
approved by the Federal Energy
Regulatory Commission (FERC or
Commission) in 1984 (1984 ASC
Methodology). On August 1, 2007, the
Administrator initiated a series of
public meetings in which informal
comment was taken on 17 specific
issues pertaining to the 1984 ASC
Methodology. Based in part on public
comment, the methodology proposed by
BPA in this notice redefines the types of
capital and expense items includable in
ASC, establishes new data sources from
which ASCs are to be derived, and
changes the nature and timing of BPA’s
procedures for review of ASC filings by
utilities participating in the REP. This
notice also contains detailed procedures
for public participation in the
consultation proceeding.
This consultation proceeding is
intended to facilitate the compilation of
a full record upon which the
Administrator will base his decision for
a final ASC Methodology. Although
preliminary informal comments have
already been made by some groups and
members of the public, this notice
formally solicits public comment. With
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the issuance of this proposal, BPA
welcomes different approaches, new
ideas and other types of feedback from
interested parties. This proposal was
developed with guidance from public
workshops and is meant to provide a
foundation that will facilitate further
ideas and approaches.
In order to participate in the REP
during FY 2009, a Pacific Northwest
utility must notify BPA of its intent to
participate by February 22, 2008. A
utility also must submit an ASC filing
(an Appendix 1) to BPA by March 3,
2008, or BPA will use the corresponding
Appendix 1 from its WP–07
Supplemental Power Rate Adjustment
Proceeding as the base filing to
determine the utility’s ASCs for FY
2009. During the comment period on the
proposed ASC Methodology, interested
parties will have the opportunity to
participate in an expedited process for
determining exchanging utilities’ ASCs
for FY 2009 based on the proposed
methodology. In addition to the
comments submitted, BPA expects to
learn through this expedited process
where improvements or changes to the
proposed methodology can be made.
Workshops will be held during the
comment period to help facilitate
feedback and explore different ideas.
BPA strives to develop, in concert with
the region, an ASC Methodology that
will be legally sustainable, efficient, and
durable over time.
ADDRESSES: Interested members of the
public may make written comments
between February 8, 2008, and May 2,
2008. Comments must be received by 5
p.m., Pacific Prevailing Time, on the
specified date in order to be considered
in the Record of Decision for the ASC
Methodology, which will be submitted
to FERC for interim and final approval.
BPA will also post written comments
online. Written comments may be made
as follows: online at BPA’s Web site:
https://www.bpa.gov/comment, by mail
to: BPA Public Affairs, DKE–7, P.O. Box
14428, Portland, OR 97293–4428, or by
facsimile to 503–230–3285. Please
identify written or electronic comments
as ‘‘2008 ASC Methodology.’’
Information and comments received by
BPA concerning the proposed ASC
Methodology will be posted at https://
www.bpa.gov/corporate/Finance/ascm.
FOR FURTHER INFORMATION CONTACT: Ms.
Michelle Manary, Manager, Residential
Exchange Program—FE–2, P.O. Box
3621, Portland, OR 97208. Ms. Leslie M.
Dimitman, Paralegal Specialist, Office of
General Counsel, LP–7, P.O. Box 3621,
Portland, OR 97208. Interested persons
may also call Ms. Dimitman at 503–230–
5515, or the general BPA toll-free
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Act gives BPA’s Administrator the
discretionary authority to determine
ASC on the basis of a methodology to
be established in consultation
proceedings. 16 U.S.C. 839c(c)(7). The
only express statutory limits on the
Table of Contents
Administrator’s authority are found in
I. Background
sections 5(c)(7)(A), (B) and (C) of the
II. The Proposed Average System Cost
Act. 16 U.S.C. 839c(c)(7)(A), (B) and (C).
Methodology
Generally, the BPA PF rate has been
lower than participating utilities’ ASCs
I. Background
under the 1984 ASC Methodology. The
A. Relevant Statutory Provisions
resulting monetary benefits BPA paid to
Section 5(c)(1) of the Northwest
participating utilities, or ‘‘net cost of the
Power Act, 16 U.S.C. 839c(c)(1),
exchange,’’ is the second attribute of the
provides that BPA shall acquire certain
REP. As noted above, the REP is not a
amounts of power offered for sale to
conventional power transaction. System
BPA by a Pacific Northwest electric
schedulers do not dispatch the
utility at the average system cost of the
exchange; line losses are not incurred.
utility’s resources in each year. In
The power purchase and sale concept
exchange, BPA shall offer to sell ‘‘an
was created by Congress for BPA
equivalent amount of electric power to
ratemaking purposes. See 16 U.S.C.
such utility for resale to that utility’s
839e(b)(1).3 Practically speaking, the
residential users within the region.’’ 1 Id. purpose of the REP is to exchange costs
Sales to the utility may not be restricted for the benefit of the residential and
below the amount of power acquired
small farm ratepayers of participating
from the utility. 16 U.S.C. 839c(c)(6).
utilities. When the BPA PF Exchange
Under this ‘‘residential exchange,’’ there rate is lower than a participating
is generally no power transferred either
utility’s ASC, BPA pays the net cost to
to or from BPA.2 The ‘‘equivalent
that utility. However, when the PF
amount of electric power’’ exchanged by Exchange rate is higher than the ASC,
BPA with the participating utility is
i.e., when the net cost of the exchange
priced at the same rate as that for
is negative, BPA has previously
general requirements sales to BPA’s
provided the utility a unilateral right to
preference customers (the ‘‘Priority Firm ‘‘deem’’ its ASC equal to the PF rate, so
or PF rate’’), subject to adjustment
that no payment flows from the utility
pursuant to section 7(b)(2) of the
to BPA.4
Northwest Power Act (the ‘‘PF Exchange
Furthermore, Northwest Power Act
rate’’). See 16 U.S.C. 839e(b)(1)–(3). By
section 5(c)(4), 16 U.S.C. 839c(c)(4),
establishing the REP, Congress intended recognizes that BPA’s PF rate, insofar as
to address the issue of wholesale rate
it applies to the REP, may carry one or
disparity that can exist between BPA’s
more ‘‘supplemental rate charges’’ after
preference customers and investorJuly 1, 1985, due to implementation of
owned customers. Because power sold
section 7(b)(3) of the Northwest Power
by BPA to exchanging utilities must be
Act. 16 U.S.C. 39e(b)(3). Were this to
treated as resold to the participating
occur and cause the PF Exchange rate to
utility’s residential consumers within
exceed a participating utility’s ASC, that
the region, ‘‘wholesale rate parity’’ is
utility has the statutory right to
achieved. This wholesale rate parity is
terminate its participation in the REP.
the first attribute of the REP.
16 U.S.C. 839c(c)(4).
In contrast, the amount paid by BPA
The monetary benefits of the REP
to the participating utility is not a
must be passed through directly to the
conventional wholesale power rate.
participating utilities’ residential and
Section 5(c)(1) of the Northwest Power
small farm consumers in accordance
Act states that BPA is to pay ‘‘the
with section 5(c)(3) of the Northwest
average system cost of that [exchanging] Power Act, 16 U.S.C. 839c(c)(3),
utility’s resources.’’ 16 U.S.C. 839c(c)(1). guarding against the possibility that the
Section 5(c)(7) of the Northwest Power
numbers 800–282–3713 (answered
Monday through Friday 6:30 a.m. to
5 p.m.) or 866–879–2303 (answered by
voice-mail).
SUPPLEMENTARY INFORMATION:
1 The
exchange was set equal to 50 percent of a
participating utility’s qualifying residential and
small farm load as of July 1, 1980, and increased
in equal annual increments to 100 percent of such
load over 5 years. See 16 U.S.C. 839c(c)(2).
2 Section 5(c)(5) allows BPA to acquire an
‘‘equivalent amount of electric power from other
sources to replace power sold to [a participating]
utility,’’ if the cost of such replacement acquisition
is less than the applicable ASC. Implementation of
this provision may result in actual power sales to
the exchanging utility.
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3 The outcome of this consultation proceeding
will not change the way in which BPA establishes
rates under section 7 of the Northwest Power Act.
The resource concept was devised by Congress to
allocate the benefits and costs of the Federal Base
System among competing classes of BPA customers.
However, the resource concept should not obfuscate
the nature of the REP as a transfer payment from
BPA to the participating utilities.
4 However, BPA has historically kept an account
of such unpaid ‘‘deemer’’ amounts, which must be
paid before the utility can receive positive REP
benefits.
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utility might set retail residential rates
that counteracted the benefits of the
REP. In addition, it is incumbent upon
BPA to establish an ASC methodology
that ensures that the net cost of the
exchange does not exceed the limits
established by Congress in the
Northwest Power Act. See 16 U.S.C.
839c(c)(7)(A), (B) and (C).
The ASC methodology must also be
designed so that BPA does not become
the ‘‘deep pocket’’ to which
participating utilities may shift
excessive or improper resource costs.
The ASC methodology should give
participating utilities an incentive to
minimize their costs. Otherwise, BPA
may not be able to satisfy the
requirement of section 7(a) of the
Northwest Power Act that its rates
recover its total revenue requirement.
BPA is a self-financing government
agency, which must recover its costs
through rates for sales of electric power
and energy.
B. Average System Cost Methodology
Background
The first ASC Methodology was
developed in consultation with the
region in 1981. See 48 FR 46,970 (Oct.
17, 1983). It was later revised in 1984.
See 49 FR 39,293 (Oct. 5, 1984); see also
PacifiCorp v. F.E.R.C., 795 F.2d 816 (9th
Cir. 1986). The 1984 ASC Methodology
has been in effect since that time. In the
mid-1990s, BPA and its participating
‘‘Utilities’’ 5 agreed to a number of
settlements that provided for payments
to each Utility through the remaining
years of the Residential Purchase and
Sale Agreements (RPSA) that implement
the REP. Because these settlements did
not require the participating utilities to
submit ASC filings, BPA temporarily
suspended its ASC review process.
Prior to BPA’s WP–02 power rate
proceeding, BPA sought to resolve REP
disputes by offering REP Settlement
Agreements (Settlement Agreements) to
regional investor-owned utilities. Under
these Agreements, BPA would provide
the participating utilities 1,000 aMW of
actual power and 900 aMW of financial
benefits for the FY 2002–2006 period,
and 2,200 aMW of benefits for FY 2007–
2011. Power sales were made at the
Residential Load (RL) Firm Power Rate.
Financial benefits were calculated based
on the difference between BPA’s RL rate
and a forecast of market prices.
The Settlement Agreements were
challenged in the U.S. Court of Appeals
for the Ninth Circuit. On May 3, 2007,
5 ‘‘Utility’’ is used here as a defined term: the
investor-owned utility or consumer-owned utility
that is a Regional Power Sales Customer that has
executed a Residential Purchase and Sale
Agreement.
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the Court held that the Settlement
Agreements executed by BPA and the
investor-owned utilities were
inconsistent with the Northwest Power
Act. See Portland General Elec. Co. v.
Bonneville Power Admin., 501 F.3d
1009 (9th Cir. 2007). As a result of the
Court’s decision, BPA must be prepared
to resume the REP by offering RPSAs to
its Utility customers. In addition to the
RPSAs, BPA is conducting this
consultation proceeding to revise the
ASC Methodology concurrent with a
section 7(i) rate proceeding to consider
revisions to the Section 7(b)(2) Legal
Interpretation and Section 7(b)(2)
Implementation Methodology,
implement the section 7(b)(2) rate test,
and develop rates consistent with the
Court’s remand in a related case. See
Golden NW Aluminum, Inc. v.
Bonneville Power Admin., 501 F.3d
1037 (9th Cir. 2007).
C. The Current Average System Cost
Methodology
Under the 1984 ASC Methodology,
utilities file with BPA ‘‘Appendix 1’’
forms containing cost information based
on rate orders from state utility
commissions or consumer-owned utility
governing bodies. BPA reviews each
Appendix 1 for conformance with
criteria specified in the Methodology.
See 18 CFR 301.1. Appendix 1 filings
are subject to review for 210 days from
the start of the relevant exchange
period, which is triggered by a change
in retail rates. Not later than 80 days
after a Utility files a new Appendix 1,
Regional Power Sales Customers or their
designee may submit written challenges
to costs included in the Utility’s
Contract System Costs. Not later than 90
days following the date the Utility files
its revised Appendix 1, BPA mails to
the Utility and all parties a list of issues
or challenged costs concerning the
Utility’s revised Appendix 1 and
requesting comments from all parties.
Written comments on the issues list
from all parties are due 30 days after the
issue list is filed. Parties may submit
cross-comments in response to
comments on the issues list up to 15
days after the written comments are
submitted. Parties may request oral
argument before the Administrator or
the Administrator’s designee up to 150
days after a Utility files a new Appendix
1. BPA also has the right under the 1984
ASC Methodology to issue a notice to
parties requesting comments on costs
that had not been challenged
previously, on Contract System Loads,
and other issues not raised previously.
Comments from parties on such notice
are due 150 days after a Utility files a
new Appendix 1. Written cross-
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comments in response to comments on
the BPA notice are due 165 days after
a Utility files a new Appendix 1.
If BPA grants a request for oral
argument, it is presented up to 180 days
after a Utility files a new Appendix 1.
BPA must issue a final determination on
the revised Appendix 1 no later than
210 days after a Utility files a new
Appendix 1.
Discovery is another component of
the 1984 ASC Methodology. BPA can
request data from a Utility any time
during the 210-day review period. The
Utility is required to respond within 30
days of receiving the data request. In
addition, parties to the ASC review can
submit data requests up to 40 days after
the Utility files its revised Appendix 1.
The Utility must respond within 65
days after the Utility files its revised
Appendix 1.
Consumer-owned utilities may
execute RPSAs for participation in the
REP. Because consumer-owned utilities
are not regulated by the state
commissions in the Pacific Northwest,
and because they are not required to
make FERC Form 1 filings, preparation
and review of ASC filings is more
burdensome for all parties concerned.
The difficulty in the preparation and
review of ASC filings has been a major
cause of disputes between BPA and
participating consumer-owned utilities
and became one of the issues leading
BPA and the consumer-owned utilities
to settle out their REP participation in
the late 1980s.
D. BPA and Customer Concerns With
the 1984 ASC Methodology
The reliance on state regulatory
agencies to determine the level of costs
included in the ASC of a participating
Utility under the 1984 ASC
Methodology, known as the
‘‘jurisdictional costing approach,’’ has
resulted in a long, burdensome,
expensive and often contentious review
process that many BPA customers said
could be improved and streamlined.
The 210-day review period for each ASC
filing under the current methodology
means that BPA and its customers are
almost always reviewing an ASC filing.
Given the tremendous advancement in
information and communication
technology (ICT) since the early 1990s,
the review process and implementation
costs can be reduced substantially
through use of electronic filings, e-mail
and other aspects of ICT without
changing the existing ASC
Methodology. However, BPA believes
that further efficiencies in the ASC
filing and review process could be
obtained if BPA were to adopt a new
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framework for obtaining the data
required for an ASC filing.
One issue related to the
‘‘jurisdictional costing approach’’ that
has not changed since REP disputes
were addressed through settlements is
the volume of utility rate orders.
Because any commission-ordered
change in retail rates triggers a new ASC
filing under the 1984 ASC Methodology,
BPA and its customers could be faced
with requirements to review several
ASC filings a year for each investorowned utility participating in the REP
because of adjustment clauses and
tracker filings in each state where the
Utility provides retail electric service to
customers.
BPA is mindful of the difficulty in
preparing ASC filings for consumerowned utilities that may want to
participate in the REP and hopes that
the proposed methodology will ease the
burden of preparing and reviewing
Appendix 1 filings.
E. Public Participation in the
Consultation Proceeding
This consultation proceeding is
intended to facilitate the compilation of
a full record upon which the
Administrator will base the decision to
establish the ASC Methodology.
Preliminary informal comments have
already been submitted by groups,
including investor-owned utilities, state
regulatory agencies and consumerowned utility customers. This notice
solicits a new round of formal
comments from interested members of
the public.
Interested members of the public may
make written comments between
February 8, 2008 and May 2, 2008.
Comments must be received by 5 p.m.,
Pacific Prevailing Time, on the specified
date in order to be considered in the
Record of Decision for the ASC
Methodology. BPA will also post
written comments online. Written
comments may be made as follows:
Online at BPA’s Web site: www.bpa.gov/
comment, by mail to: BPA Public
Affairs, DKE–7, P.O. Box 14428,
Portland, OR 97293–4428, or by
facsimile to 503–230–3285. Please
identify written or electronic comments
as ‘‘2008 ASC Methodology.’’
Information and comments received by
BPA concerning the proposed ASC
Methodology will be posted at https://
www.bpa.gov/corporate/Finance/ascm.
After the written comment stage, an
opportunity will be provided for oral
presentations before the Administrator,
which will be transcribed for inclusion
in the record. The date, time, and
location of oral presentations will be
specified in a future communication.
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Only those persons who participate in
the written comment stage of the
consultation will have the option of
making an oral presentation before the
Administrator. During any stage of the
proceeding, negotiated resolutions of
issues raised by BPA or by commenters
may be incorporated into the record by
means of written stipulations.
After completion of the foregoing
proceedings, the Administrator will
issue a Record of Decision on the
revised ASC Methodology. The revised
ASC Methodology will then be
submitted to the Federal Energy
Regulatory Commission for review and
approval.
II. The Proposed Average System Cost
Methodology
A. Introduction
The revised methodology proposed by
BPA in this notice is intended to
implement the Northwest Power Act,
help alleviate the administrative burden
and expense associated with the
jurisdictional approach to ASC
determinations, and to reflect changes
in the organization and operation of the
electric utility industry since the 1984
ASC Methodology was approved. In
preparing this proposal, BPA took into
account the issues and concerns raised
by parties during workshops held in
August through November of 2007.
Although BPA is proposing a number of
broad changes to the 1984 ASC
Methodology, the proposal is not a
complete reconstruction of the previous
1984 ASC Methodology. Several
portions of the proposal reflect features
from the 1984 ASC Methodology that
remain viable in today’s environment.
BPA anticipates that there will be a
wide variety of comments on the
proposed ASC Methodology, and also
expects that comments will raise issues
that may not have been apparent to
BPA. BPA stresses the importance of
written comments that precisely state
each commenter’s position on issues of
concern, whether the comments be
positive or negative, so that a complete
record can be compiled. Numerical
analyses and examples will be of
particular assistance to BPA in
developing a revised ASC Methodology.
BPA also welcomes negotiations and
possible settlements of issues.
B. The Uniform Cost Approach to
Determining Average System Cost
Under the Proposed Methodology
Both the 1981 and 1984 ASC
Methodologies used the jurisdictional
costing approach for ASC
determinations. As noted above, using
the jurisdictional cost approach as the
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data source for the ASC calculations has
proven to be inefficient, cumbersome,
and extremely contentious. BPA
therefore is proposing to not use a
jurisdictional costing approach for the
revised ASC Methodology. In its place,
BPA is proposing to use a data source
that is uniform and that facilitates ease
of administration for all parties. Such
data can be found for investor-owned
utilities in the FERC Form No. 1 (Form
1), a compilation of financial and
operating information prepared
annually in accordance with the
Commission’s Uniform System of
Accounts for Public Utilities and
Licensees. See 18 CFR 101 (2007). As
explained more fully below, consumerowned utilities that wish to exchange
with BPA will be required to submit
equivalent information to establish their
ASCs.
Under the proposed ASC
Methodology, the Utility may include in
its ASC only actual costs documented in
its Form 1 or equivalent, with limited
exceptions. These exceptions include
the following: First, equity return for
investor-owned utilities will be
determined in accordance with
procedures described later in this
notice; second, Federal income taxes
will be included at the marginal Federal
income tax rate; third, the Form 1 does
not always contain enough information
or level of detail to allow BPA to
determine whether costs are includable
in ASC, thus requiring supplemental
information; and fourth, BPA will
require utilities that do not file a Form
1 with FERC to submit audited financial
data in a format comparable to the Form
1 and a detailed cost of service analysis
prepared by an independent accounting
or consulting firm, approved by the
Utility’s Regulatory Body 6 and used as
the basis for setting retail rates currently
in effect.
BPA is proposing an approach for
determining a utility’s ASC that is
aimed at simplicity, transparency and
minimal administrative burden for all
parties. BPA recognizes this may make
it difficult to reflect unique
circumstances of individual utilities,
which may have an impact on their
ASCs. BPA is open to different types of
approaches and welcomes such
suggestions during the comment period.
6 ‘‘Regulatory Body’’ is used here as a defined
term: A state regulatory body, consumer-owned
utility governing body, or other entity authorized to
establish retail electric rates in a jurisdiction.
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C. Procedural Format for ASC
Determinations Under Revised ASC
Methodology
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1. ASC Determination Process
Guidelines
BPA proposes to review each Utility’s
filed ASC in a simplified administrative
process. This process will commence
during the period prior to BPA filing an
initial proposal for a change in
wholesale power rates, referred to as the
Review Period. An investor-owned
utility would submit a ‘‘base period
ASC’’ to BPA using data from the prior
year’s Form 1 on or before May 1 of each
year. For Utilities not required to submit
a Form 1 to FERC, the base period ASC
would be determined from a filing
similar in format to a Form 1. The
Utility’s base period ASC will be
projected by BPA to determine the ASC
for the BPA rate period.7 Escalating the
cost data used to determine the base
period ASC to be consistent with the
test year(s) of the BPA rate proposal
addresses many issues of temporal
consistency between ASCs and BPA’s
PF Exchange rate. As a general matter,
once the Administrator determines the
ASC for each Utility, the ASC will
remain at that level for the term of the
BPA rate period.
Proposed changes to established ASCs
would only be allowed under two
specific conditions. First, the ASC may
be adjusted in the event a Utility
acquires a new service territory or
relinquishes all or a portion of its
service territory. A second adjustment
may be made to account for major new
resource additions, purchases,
retirements or sales. In the event that a
Utility has a resource that is projected
to come on-line or be purchased and
used to meet that Utility’s retail regional
load during the BPA rate period, the
Utility will submit two ASC filings: (1)
One conforming to the Form 1 described
above, and (2) a second filing that
incorporates the costs associated with
the new resource based on the expected
commercial operation date of the new
resource or, for resource purchases, the
date the sale is completed and the costs
associated with the purchased resource
used to meet that utility’s regional retail
load. In addition to including the
estimated capital and operating costs of
the new resource, the Utility must also
estimate the changes in purchased
power expense, sales for resale credit
and other costs based on the additional
generation provided by the new
7 BPA
will forecast the utility’s ASC for an
additional four years as required for the section
7(b)(2) rate test in BPA’s wholesale power rate
adjustment proceedings.
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resource. Because the commercial online dates of power plants often change
during the construction process, BPA
will not adjust the Utility’s ASC until
the new generating resource begins
commercial operation.
For a major resource used to meet the
Utility’s regional retail load that is
projected to be unable to serve load,
retired or sold during the BPA rate
period, BPA proposes that the Utility
make two ASC filings: (1) One
conforming to the Form 1 described
above, and (2) a second filing that
excludes the costs associated with the
retired or sold resource based on the
expected retirement or closing date of
the resource. In addition to including
the reduction in estimated capital and
operating costs of the retired or sold
resource, the Utility must also estimate
the changes in purchased power
expense, sales for resale credit and other
costs based on the generation formerly
provided by the retired or sold resource.
BPA proposes not to adjust the Utility’s
ASC until the official retirement or
transfer date of the generating resource.
BPA proposes that all Utilities be
required to submit ASC filings using
BPA’s electronic template (Appendix
1) 8 on or before May 1 of every year.
Several areas of the ASC filing template
require additional data and/or analyses.
The additional data/analyses must also
be in electronic format and submitted at
the same time as the Appendix 1
template. The filing, along with the
additional data and support, will be
made available to BPA customers and
other parties for review through BPA’s
external Web site. Each filing may be
reviewed by BPA or its designee to
determine whether the costs are
consistent with Generally Accepted
Accounting Principles for electric
utilities and consistent with the ASC
Methodology.
BPA envisions that this approach will
reduce the time, administrative burden
and cost to BPA, the Utility, other BPA
customers and other interested parties
without significantly affecting the
accuracy of the ASC determination
when compared to the more
cumbersome process required under the
1984 ASC Methodology. BPA proposes
that ASC determinations prior to BPA’s
rate cases will replace the multiple
determinations in each year required
under the 1984 ASC Methodology for
each jurisdiction in which a Utility
provides retail residential service upon
each change in retail rates.
8 Appendix 1 refers to the appendix to both the
current and proposed ASC methodology containing
the form on which the exchanging utility reports its
Contract System Costs and other information
required for the calculation of ASC.
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The revised ASC Methodology has
characteristics similar to ratemaking
based on an historical test year
incorporating end-of-year data. Each
Utility would be permitted to include
the same types of costs in ASC based on
actual data from the same calendar-year
period. It is uniform in contrast to the
1984 ASC Methodology, which relied
on data from retail rate proceedings
throughout the Northwest, each using
different ratemaking methodologies and
test years.
Although the numbers included in
Form 1 accounts by Utilities will help
expedite ASC reviews, Utilities’ ASC
filings will continue to be scrutinized by
BPA, its customers and other
participants in the ASC review process.
BPA has a statutory responsibility to
ensure that all improper costs are
excluded from ASCs. Each ASC filing
must contain a statement, signed by a
senior officer of the Utility, stating that
all data submitted by the Utility were
compiled in strict compliance with the
Commission’s Uniform System of
Accounts, the ASC Methodology, and
Generally Accepted Accounting
Principles, and are consistent with
applicable orders and policies of their
Regulatory Body. For Utilities not
required to submit a Form 1, the
attestation will state that the data were
compiled in strict compliance with the
Utility’s financial statements, the ASC
Methodology, and policies and orders
from the Utility’s Regulatory Body. BPA
proposes that any filing that does not
contain this attestation will not be
accepted by BPA for determination of an
ASC.
BPA invites and welcomes comments
on alternative sources of verifiable data
for use in determining ASC. Such
comments should contain detailed
explanations of the verification
safeguards inherent in any proposed
alternative as well as procedural
alternatives.
2. Transition Implementation of the REP
BPA hopes to begin the
implementation of the REP for eligible
utilities on October 1, 2008. To do so,
BPA must negotiate and execute new
RPSAs with Utilities, establish a revised
ASC Methodology, and establish ASCs
under the revised Methodology. As
noted below, BPA also intends to
implement the proposed ASC
Methodology in an expedited ASC
review during the spring of 2008 in
order to identify any problems that
might arise in implementing the
Methodology. The results of the
expedited ASC review will be used as
a starting point for the determination of
final ASCs for FY 2009. The expedited
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ASC review will be implemented as
follows.
After publication of the proposed ASC
Methodology, a Utility intending to
participate in the REP beginning
October 1, 2008, must notify BPA of its
intent by February 22, 2008. If a Utility
fails to notify BPA of its intent to
participate in the REP in FY 2009 by
February 29, 2008, the Utility will be
ineligible to receive any REP benefits
during the FY 2009 rate period. A
Utility must file its Appendix 1 based
on the proposed ASC Methodology with
BPA by March 3, 2008. If it fails to do
so, BPA will rely on the Appendix 1 for
the Utility included by BPA in its WP–
07 Supplemental Rate Proposal to
determine ASCs for FY 2009. BPA will
provide electronic access to the
Appendix 1 filings on March 4, 2008, to
all Regional Power Sales Customers and
other interested parties. BPA will
review all Appendix 1 filings
concurrently in an expedited public
process. Interested parties will have the
opportunity to intervene in BPA’s
review. Petitions to intervene must be
filed with BPA by March 11, 2008. Data
requests must be submitted by March
14, 2008. BPA will commence discovery
workshops on all Appendix 1 filings on
March 26, 2008. BPA and parties will
address and resolve all discovery issues
in the workshops. BPA and parties may
electronically file an issue list
identifying and providing full
arguments regarding the contested
elements of a Utility’s Appendix 1 filing
by April 10, 2008. The Utility will
electronically file, and other parties may
file, a response to the issue lists on
April 24, 2008. A second workshop will
be held on April 29, 2008, to discuss
and resolve, to the extent possible, the
identified issues. BPA will then review
the parties’ arguments, rule on such
issues, and publish and electronically
serve all parties with a Draft ASC
Reports on May 9, 2008. The Utility and
parties may file comments on the Draft
ASC Reports by May 23, 2008. After
reviewing the comments, the BPA
Administrator will issue Final ASC
Reports on June 6, 2008.
After BPA develops the final
proposed ASC Methodology, BPA will
file the Methodology with FERC for
confirmation and approval. BPA hopes
to receive interim approval of the
Methodology on or around September 1,
2008. After FERC approval, BPA
proposes to review the ASC
determinations resulting from the
expedited ASC review. BPA will
compare the proposed ASC
Methodology provisions with the FERCapproved Methodology. If there are no
differences between the data included
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in the Utilities’ initial Appendix 1s (or
the Appendix 1 filings developed by
BPA for the WP–07 Supplemental Rate
Proposal) and the Appendix 1s to be
filed under the final Methodology, the
Utilities’ initial Appendix 1s (or the
default WP–07 Supplemental Appendix
1s) can be used for the Utilities’ final
ASC determinations. If the Appendix 1s
are the same but the substantive criteria
of the Methodology have changed from
the initial proposed Methodology, BPA
will recalculate each Utility’s ASC by
reviewing the initial Appendix 1 and
applying the final Methodology criteria.
Because the Utility’s initial Appendix 1
will have been reviewed in the
expedited review, BPA will conduct an
abbreviated review with all interested
parties to ensure that the Utilities’ ASCs
comply with the FERC-approved
Methodology. If BPA determines that
the ASCs comply, BPA will establish
the ASCs as the Utilities’ final ASCs for
FY 2009.
BPA also must plan for the
establishment of each Utility’s ASC for
FY 2010–2011. Under the proposed ASC
Methodology, except for the initial oneyear Exchange Period under the revised
Methodology, and the second Exchange
Period for FY 2010–2011, a Utility must
file an Appendix 1 by May 1 of each
year. If a Utility wishes to participate in
the REP in the second Exchange Period
for FY 2010–2011, it must file an
Appendix 1 using 2007 data by July 1,
2008. If a Utility fails to file an
Appendix 1 by July 1, 2008, the Utility
will receive no REP benefits for the FY
2010–2011 period. After receiving all
exchanging Utilities’ Appendix 1s by
July 1, 2008, BPA will promptly publish
a schedule for review of the filings.
Although BPA hopes to complete this
review using the ASC review schedule
contained in the ASC Methodology,
BPA may issue a schedule different
from the prescribed schedule in order to
ensure that ASCs for FY 2010–2011 are
established in time to be incorporated in
BPA’s FY 2010–2011 wholesale power
rate initial proposal. After completing
its ASC review process, BPA will
establish ASCs for FY 2010–2011. If
FERC approval of the ASC Methodology
is subsequent to this ASC review, BPA
will compare the Methodology used to
calculate the ASCs with the FERCapproved Methodology. BPA will
conduct an abbreviated ASC review will
all interested parties to ensure that
Utilities’ ASCs comply with the final
Methodology. If BPA determines that
the ASCs comply, BPA will establish
the ASCs as the Utilities’ final ASCs for
FY 2010–2011.
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D. Invoicing and Payment Using Actual
Residential Load
Although not a part of the ASC
Methodology, BPA proposes to continue
the contractual requirement that
Utilities invoice BPA monthly based on
actual eligible residential and small
farm loads. A Utility’s monthly REP
payment is determined by subtracting
the Utility’s BPA PF Exchange Rate 9
from the Utility’s ASC, and then
multiplying the result by the Utility’s
actual eligible monthly residential and
small farm load.
E. Treatment of Certain Resource Costs
Under the Proposed Average System
Cost Methodology
1. Transmission Investments and
Related Expenses Included in Contract
System Costs
Transmission investments and
expenses were included in ASCs under
BPA’s 1981 ASC Methodology. The
1981 ASC Methodology was established
pursuant to a negotiated settlement,
agreed to by all parties. The
Administrator’s 1981 ASC Methodology
Decision, at 1–2, explains the process by
which most issues, including the
propriety of adding transmission costs
to ASC, were resolved through a
negotiated settlement in the first
consultation proceeding. The
Commission granted final approval to
the 1981 ASC Methodology on October
17, 1983. See Sales of Electric Power to
Bonneville Power Admin., Methodology
and Filing Requirements, 48 FR 46,970
(Oct. 17, 1983).
In the 1984 ASC Methodology, BPA
included ‘‘all existing transmission, as
defined in the Commission Uniform
System of Accounts, in service as of July
1, 1984 * * *’’ and ‘‘[f]or transmission
plant commencing service after July 1,
1984, transmission plant costs that can
be exchanged are limited to
transmission facilities that are directly
required to integrate resources to the
transmission grid.’’ 10 The Commission
granted final approval to the 1984 ASC
Methodology on October 5, 1984, which
continued to allow certain transmission
costs in ASC. See Methodology for Sales
of Electric Power to Bonneville Power
Administration, 49 FR 39,293 (October
9 BPA is proposing in the WP–07 Supplemental
Rate Proceeding to develop either Utility-specific
PF Exchange rates or a PF Exchange rate with
Utility-specific supplemental rate charges. In either
case, the applicable BPA rate will be determined
specifically for each Utility. This rate determination
methodology requires that BPA know during the
rate proceeding which Utilities intend to participate
in the REP.
10 1984 Administrator’s Record of Decision,
Average System Cost Methodology at 42.
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5, 1984), FERC Statutes and Regulations
¶ 30,601.
Even though the 1984 ASC
Methodology allowed all transmission
prior to 1984 but only a portion of it
after 1984, upon further consideration
BPA believes transmission should be
included in the calculation of utilities’
ASCs. One of the main reasons for this
conclusion is that the exclusion of the
transmission component of electricity
production and delivery may introduce
an inequity between Utilities that
develop resources close to their service
territory and those that develop
geographically distant resources.
Therefore, BPA proposes that the cost of
resources should include all costs
associated with the delivery of power to
the Utility’s load centers.
Furthermore, since implementation of
the 1984 ASC Methodology and its
approval by the Commission, the
electric utility industry has undergone
significant changes in structure,
specifically, the development of
wholesale power markets, creation of
regional transmission organizations
(RTOs) and the separation of generation
and transmission functions of vertically
integrated electric utilities mandated by
Commission Order 888, which was
issued in 1996. In 1999, BPA
administratively separated its power
and transmission functions to
voluntarily comply with the
Commission’s order for investor-owned
utilities to separate generation and
transmission. Consequently, BPA now
develops separate rates for power and
transmission.
As a result of this change in industry
structure, electric utilities have a variety
of ways to acquire generation to serve
their retail load. For example, utilities
can: (1) Rely on wholesale power
markets; (2) build centralized generation
units close to the fuel source; or (3)
build the generation close to the load
center and transport the fuel source (e.g.
coal by rail). In addition, many large
power plants are owned by more than
one utility. This diversity in the method
of acquiring electric generating capacity
to serve retail load means that excluding
transmission costs from the ASC
calculation would have adverse effects
on Utilities. Exclusion of the
transmission component of electricity
production and delivery would
introduce an inequity between Utilities
that develop resources close to their
service territory and those that develop
geographically distant resources. In
summary, BPA proposes that the cost of
resources should include the cost of
transmission used to deliver resources
to retail load.
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2. Treatment of Conservation Costs
In the 1984 ASC Methodology, the
Administrator determined which
conservation costs could be included in
ASCs. The determinations ‘‘were case
specific, based on the information
provided by exchanging utilities.’’ 11
Generally, the 1984 ASC Methodology
allows Utilities to include only the costs
of ‘‘measures for which power is saved
by physical improvements or devices.
Advertising, promotion and audit
expenses are not resource costs and
therefore are not includable in the
ASC.’’ 12
BPA proposes to continue with the
1984 ASC Methodology’s exclusion of
advertising and promotion costs, except
that the revised Methodology will allow
Utilities to include the cost of energy
audits. BPA proposes to allow energy
audits because the only way to
determine if a conservation program or
measure will be cost effective is through
an analysis or ‘‘audit’’ of the facility
where the conservation measure will be
installed. Some items such as energy
efficient light bulbs are cost effective in
almost any location. Others, like
insulation, energy efficient windows or
HVAC upgrade/replacements must be
analyzed in advance to see if the
measure is cost effective. In many ways,
the audit is a form of or extension to the
Utility’s least-cost plan. If the audit is
not done before the measure is installed,
the funds could be used on a measure
that is not cost effective. For this reason,
BPA believes it is reasonable to allow
the costs of audits in the ASC
calculation.
3. Treatment of Oregon’s Public Purpose
Charge Related to the Acquisition of
Conservation and Renewable Resources
Oregon’s Public Purpose Charge
(OPPC) was established in 1999 with
passage of Oregon’s electricity
restructuring law, Senate Bill 1149. See
generally, Or. Rev. Stat. § 757.612
(2005). The OPPC was established to
‘‘fund new cost effective local energy
conservation, new market
transformation efforts, the above-market
costs of renewable energy resources and
new low income weatherization.’’ Id. at
§ 757.612(2)(a). The OPPC is set at 3
percent of total retail sales of electricity
for PacifiCorp-Oregon, Portland General
Electric (PGE) and Idaho Power-Oregon.
Id. The OPPC applies to consumerowned utilities only if they allow direct
access to any class of their customers.
Id. At this time, BPA is not aware of any
consumer-owned utilities that are
11 1984
ASC Methodology Record of Decision at
73.
12 Id.
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participating in OPPC program. The
OPPC replaces the conservation/DSM
programs PGE, PacifiCorp-Oregon and
Idaho Power-Oregon operated before
Oregon SB 1149. When the OPPC was
implemented by the utilities, the OPUC
was directed to remove the costs of
OPPC-like programs from retail rates. Id.
at § 757.612(3)(g).
The OPPC was implemented on
March 1, 2002, for PGE and PacifiCorpOregon, and in 2006 for Idaho PowerOregon. Distribution of the OPPC funds
are made monthly by the utilities to the
following organizations in the following
percentages:
Energy Trust of Oregon (ETO)—73.8%
Education Service Districts (ESD)—
10.0%
Oregon Housing and Community
Services (OHCS)—16.2%
PGE, PacifiCorp and Idaho Power do
not show the OPPC on their financial
statements or Form 1s. The utilities treat
the revenue and expense as a direct
pass-through. Accounting records are
available from the utilities showing the
revenue received and the payments
made to the three recipient
organizations. SB 1149 states that the
OPPC funds be allocated in the
following manner:
New cost-effective conservation and
market transformation—63%
Above market cost of renewable energy
resources—19%
Low-income weatherization—13%
Low-income bill payment assistance—
5%
The 1981 and the 1984 ASC
Methodologies did not address the cost
treatment of charges like the OPPC. A
key attribute of the OPPC has been that
it effectively replaces the Utility’s
conservation program, which is
typically included as part of a Utility’s
base rates. Because of this unique
feature, BPA proposes that the OPPC is
an alternative form of acquiring
conservation and renewable resources,
and therefore should be considered in
determining ASC. In the same way that
some utilities build thermal resources
and others purchase power from the
market, BPA proposes that the OPPC is
a similar method of acquiring
conservation and renewable resources.
Another way of looking at the OPPC is
as an outsourcing arrangement. While
some utilities have their own
conservation departments and
programs, Oregon investor-owned
utilities are effectively required to
‘‘outsource’’ their conservation activities
to the ETO, OHCS and ESDs. BPA needs
to have the right to review and audit the
costs and programs of the organizations
that receive OPPC funds in order to
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determine the portion of the Utility’s
costs that are excludable from their
ASC. If an OPPC-recipient organization
denies BPA the right to review and
audit its costs and programs, then BPA
will not include such costs in the
Utility’s ASC calculation. BPA will
review the OPPC costs and functionalize
the costs using the same procedure as
used in reviewing Utility conservation
costs.
4. Treatment of Return on Equity and
Federal Income Taxes
In the Federal Register Notice for the
1984 ASC Methodology proposal, BPA
stated that ‘‘[i]n developing an ASC
methodology the BPA Administrator has
considerable discretion in deciding
whether to permit inclusion of an equity
return allowance and, if so, how that
component is to be determined.’’ 13 The
Administrator’s discretion was affirmed
by the Commission in its order
approving the 1984 ASC
Methodology.14 In the 1984 ASC
Methodology, BPA excluded the cost of
equity in the ASC determination in part
because of concern that Regulatory
Bodies may increase the allowed return
on equity (ROE) to compensate Utilities
for the cost of terminated plants and
because ROE is primarily associated
with the default risk of investor-owned
utilities. On review, the Ninth Circuit
affirmed BPA’s view that ROE be
excluded from the ASC calculation in
light of BPA’s experience with
implementing the program and its need
to avoid abuses. PacifiCorp v. F.E.R.C.,
795 F.2d 816, 823 (9th Cir. 1986). In
making this finding, though, the Court
held that ‘‘[t]he statute itself, however,
neither commands nor proscribes these
adjustments in ASC methodology.’’ Id.
Consequently, the Court noted that it
did not ‘‘sanction any permanent
implementation of these exclusions.’’ Id.
at 823.
The 1984 ASC Methodology did not
allow ROE in ASCs, but instead
permitted the inclusion of the Utility’s
long-term cost of debt. BPA now
proposes that ROE should be allowable
in ASC. The cost of debt is a cost of
resources and, in the case of investorowned utilities, the cost of debt is
13 49
FR 4230, 4235 (Feb. 3, 1984).
FR 39,293, 39,296 (Oct. 5, 1984): Congress
chose the Administrator to determine cost of utility
resources. Had the Congress intended that the
Administrator must follow State commission
determinations of a utility’s resource costs, it could
have easily included this requirement in the statute
or simply left the Administrator out altogether and
let the State commissions develop the ASC
methodology. This was not done. The
Administrator was chosen to develop a
methodology to determine ASC, subject to the
Commission’s review.
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lowered by the contribution of equity by
the company. Without the spreading of
risk to shareholders there would be a
significant increase in the cost of debt.
State commissions and rating agencies
require investor-owned utilities to
maintain specific capital structures that
affect the company’s debt ratings.
Therefore, debt alone is not an adequate
reflection of the capital cost of a
Utility’s resources. Without an equity
component in the cost of capital, a
higher cost of debt is needed to reflect
the true cost of financing resources.
BPA finds that enough changes have
occurred in the PNW regulatory
environment to reasonably ensure that
terminated plant costs will not be
included with allowable costs under the
ASC Methodology. First, the costs of the
Pebble Springs nuclear plant that were
the basis of the terminated plant
controversy in the mid-1980s have been
completely written off by the utilities
involved. Second, Oregon’s
establishment of a three-person
appointed public utility commission
greatly reduces the chance of improper
communications between the Oregon
PUC and utilities. Third, since 1984,
Oregon has had a Citizens’ Utility Board
(CUB), which monitors the retail rate
development of utilities conducting
business in Oregon. CUB reviews retail
rates in order to ensure, among other
things, that terminated plant costs are
excluded from such rates. Additionally,
increased disclosure and filing
requirements at the commission level
make identifying inappropriate costs
much easier. All four state commissions
now have requirements that utilities
under their review prepare Integrated
Resource Plans. From these filings, BPA
and its customers can likely determine
if a Utility included the costs of
terminated plant in its equity
calculation. Thus, the risk that
Regulatory Bodies will include
inappropriate costs in the ROE has
diminished significantly since 1984.
Because of these changes, and based
on BPA’s experience in implementing
the ASC, BPA now proposes that
Utilities should be allowed to exchange
ROE. In the revised ASC Methodology,
BPA is proposing to allow return on
equity as determined by the Regulatory
Bodies at a Utility’s most recent
commission-approved level. For
purposes of determining return on rate
base, the Utility will include the
weighted cost of capital from its most
recent rate order. For Utilities with
service territories in more than one
state, the Utility shall submit a weighted
cost of capital based on the most recent
Regulatory Body rate orders weighted by
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rate base in states within the PNW
region.
In the 1984 ASC Methodology, BPA
did not allow the inclusion of Federal
income taxes in ASC. BPA’s rationale
stated that ‘‘nothing in the [Northwest
Power] Act or its legislative history
requires the inclusion or exclusion of
income taxes in computing the average
system cost of a Utility’s resources.’’ 15
The Commission approved BPA’s
interpretation, albeit with some
reservation because of an apparent
‘‘contradiction’’ in the allowance of a
proxy for equity returns elsewhere in
the methodology.16 On review, the
Ninth Circuit was equally reserved
when reviewing the 1984 ASC
Methodology. PacifiCorp, 795 F.2d at
823. As with ROE, which was decided
in the same opinion, the Court affirmed
BPA’s interpretation with the notation
that it did not ‘‘sanction any permanent
implementation of these exclusions.’’ Id.
Under the revised ASC Methodology,
BPA is proposing to allow Utilities to
exchange the costs of certain taxes
through their ASCs. BPA is proposing
this change because it is necessary to
have symmetry between its treatment of
ROE and taxes. As noted above, BPA is
proposing to allow the costs associated
with equity return as a resource cost in
calculation of ASC. If the cost of Federal
income taxes at the marginal tax rate is
not also included, then an investorowned utility’s cost of resources would
be understated. When calculating the
revenue requirement for an investorowned utility, Regulatory Bodies
typically gross up the cost of equity by
the marginal Federal income tax rate to
arrive at the ‘‘after tax’’ return. In the
same manner, because BPA is proposing
to include ROE as a resource cost in the
ASC Methodology, BPA is also
proposing to gross up the equity
component by the Federal income tax
rate when determining an investorowned utility’s weighted cost of capital
in ASC.
5. Functionalization of Regulatory
Assets and Liabilities in ASC
Regulatory assets and liabilities are
expenses, revenues, gains or losses that
would normally be recognized in net
income in one period, but for an order
of a Regulatory Body specifying a
different recovery period in retail rates.
Regulatory Assets and Liabilities,
Accounts 182.3 and 254 in the
Commission Uniform System of
Accounts, were established in March
1993 in Commission Order No. 552,
15 1984 Administrator’s Record of Decision,
Average System Cost Methodology at 59.
16 49 FR 39,293, 39,297 (Oct. 4, 1984).
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Federal Register / Vol. 73, No. 26 / Thursday, February 7, 2008 / Notices
which established uniform accounting
treatment for allowances associated
with the 1990 Clean Air Act. Order No.
552 also dealt more broadly with
accounting for regulatory assets and
liabilities for electric and gas utilities.17
Regulatory assets and liabilities were
not addressed in the 1984 ASC
Methodology.
For investor-owned utilities located in
the Pacific Northwest, regulatory assets
and liabilities are a significant portion
of the balance sheet. Examples of costs
and revenues that can be deferred and
included as a regulatory asset or liability
with Regulatory Body approval include:
fuel costs subject to a power cost
adjustment, storm damage, gains on
reacquired debt, deferred compensation
plans, stranded costs, phase-in plans,
deferred income taxes, asset retirement
obligations, asset impairment or
disposal under Financial Accounting
Standards Board 144, rate case expenses
and intervenor funding, buyout costs for
non-utility generation, deferred
purchase capacity costs, deferred
demand-side management costs, U.S.
Department of Energy (USDOE) nuclear
fuel enrichment clean-up fees, deferred
revenue related to income taxes
associated with allowance for funds
used during construction (AFUDC),
unamortized loss on reacquired debt,
and deferred return on sales of emission
allowances. The above list is only
representative of the deferred costs and
revenues that would be found in a
typical Form No.1 or a Regulatory Body
rate or accounting order.
There are three major issues for the
revised ASC Methodology relating to
treatment of regulatory assets and
liabilities. First, how should regulatory
assets and regulatory liabilities be
functionalized between production,
transmission, and distribution? Second,
for the production-related assets and
liabilities, what rate of return, if any,
should the Utility earn on these items
for purposes of determining a Utility’s
ASC? And finally, how should the
amortization of regulatory assets and
liabilities be handled in the ASC review
process?
Functionalization of regulatory assets
and liabilities raises several problems
because of the lack of information
contained in the Form 1 concerning the
nature of these items. Descriptions of
regulatory assets and liabilities are
cryptic at best. Some of the deferred
costs are of a short-term nature, such as
power costs, which may be carried as a
deferral for a matter of months. Other
costs may be deferred and amortized 5
17 G. Hahne and G. Aliff, Public Utility
Accounting 11–5 (Mathew Binder 2005).
VerDate Aug<31>2005
17:02 Feb 06, 2008
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years or more, such as costs associated
with storm damage and conservation.
The Form 1 provides little or no detail
on the length of the deferral period for
each item. Nor does it provide
information on whether the deferred
assets and liabilities are included in rate
base by the Utility’s Regulatory Body. A
brief review of several regional
Regulatory Body rate orders revealed
few references to regulatory assets in the
list of items included in rate base.
Finally, the Commission’s Uniform
System of Accounts does not provide
specific rules for amortization of
regulatory assets. Review of the
Utilities’ Form 1 filings reveal that some
utilities amortize regulatory assets and
liabilities to Accounts 407.3, Regulatory
Debits and 407.4, Regulatory Credits,
while others amortize regulatory assets
and liabilities to specific income or
expense accounts. For these reasons,
BPA proposes that Utilities must
perform a direct analysis and
functionalize all regulatory assets and
liabilities to Production, Transmission,
or Distribution/Other. The Utility must
provide documentation supporting its
rationale for functionalization of the
regulatory asset or liability. This
documentation must consist of general
ledger entries, a description of the item
in sufficient detail to permit BPA to
determine the functional nature of the
cost, and all communications on the
asset or liability between the Utility, its
Regulatory Body and its external
auditor. The documentation must also
show that the asset or liability is
included in the Utility’s calculation of
rate base approved by its Regulatory
Body and the allowed return or carrying
cost. In no case will the amount of
regulatory assets and liabilities allowed
in ASC exceed the amount included in
retail rates for the same period by the
regional Regulatory Bodies.
6. Treatment of Cash Working Capital in
ASC
Cash Working Capital (CWC) is a
component in almost all Regulatory
Body determinations of rate base.
Inclusion of CWC as an element of rate
base is consistent with the principle that
investors receive a fair return on
investment that is used, useful and
devoted to public service. One
definition of CWC as used in regulatory
proceedings is:
The average amount of capital provided by
investors, over and above the investment in
plant and other specifically measured rate
base items, to bridge the gap between the
time expenditures are required to provide
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services and the time collections are received
for such services.18
Because the 1981 and 1984
Methodologies relied on the
jurisdictional approach, CWC was a part
of the Utilities’ rate base calculation in
Regulatory Body rate orders. The 1981
and 1984 Methodologies simply set an
upper limit on the amount of CWC
included in rate base for the ASC
calculation.19
Because the revised ASC
Methodology proposes to use the Form
1 (which does not include a CWC value)
as the basis for data for ASC filings, BPA
believes it is important to include a
separate determined value for CWC in
the Utility’s rate base calculation for
ASC purposes. While determination of
the proper amount of CWC in rate base
is often very controversial, a standard
and widely accepted measure is oneeighth of total O&M costs, less fuel and
purchase power costs.20 This one-eighth
formula was the cap or maximum
amount that BPA allowed for CWC in
the 1984 ASC Methodology.
BPA is proposing to use this
formula—one-eighth of total
exchangeable O&M costs, less fuel and
purchase power costs—for the CWC
value included in the Appendix 1 filing.
The details are shown in Schedule 1A
of the revised ASC Methodology
template.
7. Single ASC for Multi-Jurisdictional
Utilities
Under the 1981 and 1984 ASC
Methodologies, BPA used a
jurisdictional approach to determining a
Utility’s ASC. For Avista, Idaho and
PacifiCorp, Utilities that serve retail
customers in more than one state,
reliance on Regulatory Body rate orders
for ASC determinations resulted in
separate ASC filings for each state.
Developing ASCs by state for multijurisdictional Utilities presents
problems for those utilities because
Form 1 filings are prepared on a total
utility basis, and trying to separate and
allocate the costs from the total system
to individual states would be
burdensome and expensive for both the
Utility and BPA. For this proposal, BPA
proposes to develop a single ASC for
each Utility. Because PacifiCorp has
service territories that are outside the
Pacific Northwest region, it will be
required to submit an ASC filing based
on an allocation of its in-region
resources and costs, based on the
individual state results of operations
18 Id.
at 5–4.
18 CFR 301.1 FN. h.
20 G. Hahne and G. Aliff, Public Utility
Accounting 5–5 (Mathew Binder 2005).
19 See
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filings PacifiCorp files with each
Regulatory Body.
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8. Treatment of Purchased Power and
Sales for Resale Credit
Purchased power and sales for resale
are subject to significant variability for
a number of reasons including:
Temperature—colder than normal
winters increase the demand for
electricity, resulting in increased
purchases of electricity for utilities that
rely on market purchases for meeting a
portion of retail load.
Precipitation—heavier than normal
precipitation in the Columbia River
Basin increases the amount of electricity
available at the regional hydroelectric
facilities and could lower the need for
additional electricity.
Prices—the price of electricity
purchased by utilities varies with
temperature and precipitation, but also
the price of natural gas, which is the
fuel on the margin for most hours of the
year, and therefore affects the price of
electricity in power markets.
Regulatory Bodies use a process
called normalization to adjust quantity
and price for purchased power and sales
for resale in regulatory proceedings.
Normalization of purchased power and
sales for resale credits is a process used
by utilities and Regulatory Bodies to
adjust actual data to reflect what would
likely occur under conditions (water,
weather, market prices) that are closer to
long-term averages. For this reason, BPA
proposes to generally use a rolling 5year average of short-term (less than 1
year) energy sales and energy purchases
in the Appendix 1. For pricing, BPA
proposes to use the same models and
methodologies used to develop market
price forecasts in BPA’s wholesale
power rate filings.
BPA understands this area is not
simple, and its treatment can have a big
impact on hydro-intensive utilities. BPA
welcomes different approaches and
ideas on how to account for the
significant variability in this area.
9. Future Revision of Average System
Cost Methodology To Address Tiered
Rate Issues
BPA and its customers are currently
discussing the design of a Tiered Rates
Methodology (TRM) for BPA’s future
wholesale power rates. BPA expects to
conduct a hearing under section 7(i) of
the Northwest Power Act in 2008 in
order to establish a TRM, which would
be implemented in the rate period
beginning FY 2012. The establishment
of the TRM may affect the
implementation of the REP for
consumer-owned utilities. For example,
BPA may propose as part of the TRM
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17:02 Feb 06, 2008
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that a consumer-owned utility that
elects to receive an individual Contract
High Water Mark will have an ASC that
excludes costs of any resources added
by the utility after September 30, 2006.
Other REP-related proposals and issues
will undoubtedly be raised in
connection with the TRM.
Consequently, BPA has included
placeholder language in the Proposed
Revised Average System Cost
Methodology that the Methodology will
be revised if necessary or appropriate to
accommodate establishment and
implementation of tiered rates.
The Proposed Revised Average
System Cost Methodology,
Functionalization for Average System
Cost Methodology, Endnotes and the
Proposed Average System Cost template
are incorporated herein by reference and
are available at the following link:
https://www.bpa.gov/corporate/Finance/
ascm.
In consideration of the foregoing
discussion, BPA proposes to revise the
Average System Cost Methodology as
set forth below.
Issued in Portland, Oregon, January 31,
2008.
Stephen J. Wright,
Administrator and Chief Executive Officer.
[FR Doc. E8–2258 Filed 2–6–08; 8:45 am]
BILLING CODE 6450–01–P
DEPARTMENT OF ENERGY
Bonneville Power Administration
[BPA Docket No. WI–09]
Proposed Wind Integration—WithinHour Balancing Service Rate for Public
Hearing, and Opportunity for Public
Review and Comment
7279
Persons wishing to intervene and
become parties in the rate case must file
a petition to intervene by 5 p.m., Pacific
Standard Time, on February 13, 2008.
The petition must state the name and
address of the intervenor and the
intervenor’s interest in the outcome of
the proceeding. Written comments by
non-party participants must be received
by BPA no later than April 15, 2008, to
be considered in the Record of Decision
(‘‘ROD’’). The Administrator will issue a
Final Record of Decision in these
proceedings by July 28, 2008.
ADDRESSES: Petitions to intervene
should be directed to Brandon Hignite,
Hearing Clerk—2009 Wind Integration
Rate Case, L–7, Bonneville Power
Administration, 905 NE 11th Avenue,
Portland, OR 97232 or by e-mail to:
wi09rate@bpa.gov, and must be received
no later than 5 p.m., Pacific Standard
Time, on February 13, 2008. In addition,
a copy of the petition must be served
concurrently on BPA’s General Counsel
and directed to Barry Bennett, LC–7,
Office of General Counsel, Bonneville
Power Administration, 905 NE 11th
Avenue, Portland, OR 97232 or by email to: bbennett@bpa.gov. Written
comments may be made online at BPA’s
website: www.bpa.gov/comment, or by
mail to: BPA Public Affairs, DKE–7, P.O.
Box 14428, Portland, OR, 97293–4428.
Please label your submission ‘‘2009
Wind Integration Rate Case.’’
FOR FURTHER INFORMATION CONTACT: Mr.
Elliot E. Mainzer, Transmission Policy
and Strategy Manager, at (360) 619–
6252.
DATES:
SUPPLEMENTARY INFORMATION:
Part I—Introduction and Procedural
Background
AGENCY:
A. Statutory Provisions Governing This
Rate Proceeding
SUMMARY: The purpose of the hearing is
to adopt a rate for Wind Integration—
Within-Hour Balancing Service. As
increasing amounts of wind generation
have integrated into BPA’s Balancing
Authority, the variability and
uncertainty of wind generation have led
to increased costs through the need for
additional reserve capacity, the shift of
energy generation from heavy load
hours to light load hours, and reduced
system efficiency. The Wind
Integration—Within-Hour Balancing
Service rate will ensure that these costs
are borne by the parties causing the
costs.
Section 7 of the Northwest Power Act,
16 U.S.C. 839e, sets forth a number of
general directives that the BPA
Administrator must consider in
establishing rates for the sale of electric
energy and capacity and transmission
services. In particular, section 7(a)(1), 16
U.S.C. 839e(a)(1), provides in part that
‘‘[s]uch rates shall be established and, as
appropriate, revised to recover, in
accordance with sound business
principles, the costs associated with the
acquisition, conservation, and
transmission of electric power,
including the amortization of the
Federal investment in the Federal
Columbia River Power System (FCRPS)
(including irrigation costs required to be
repaid out of power revenues) over a
reasonable period of years and the other
costs and expenses incurred by the
Bonneville Power
Administration (BPA), Department of
Energy (DOE).
ACTION: Notice of Wind Integration—
Within-Hour Balancing Service Rate
(Notice), BPA Docket No. WI–09.
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Agencies
[Federal Register Volume 73, Number 26 (Thursday, February 7, 2008)]
[Notices]
[Pages 7270-7279]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-2258]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Bonneville Power Administration
Proposed Methodology for Determining the Average System Cost of
Resources for Electric Utilities Participating in the Residential
Exchange Program Established by Section 5(c) of the Pacific Northwest
Electric Power Planning and Conservation Act
AGENCY: Bonneville Power Administration (BPA), DOE.
ACTION: Notice; request for comments (BPA File No.: ASCM-08).
-----------------------------------------------------------------------
SUMMARY: Bonneville Power Administration (BPA) proposes a revised
methodology for determining the average system cost (ASC) of resources
for regional electric utilities that participate in the Residential
Exchange Program (REP) authorized by section 5(c) of the Pacific
Northwest Electric Power Planning and Conservation Act (Northwest Power
Act). The ASC methodology is used in the determination of monetary
benefits paid by BPA to utilities participating in the REP. The
Northwest Power Act authorizes the BPA Administrator to determine
utilities' ASCs based on a methodology developed by BPA in consultation
with the Northwest Power and Conservation Council, BPA customers and
state regulatory agencies in the Pacific Northwest. The existing
methodology was adopted by BPA and approved by the Federal Energy
Regulatory Commission (FERC or Commission) in 1984 (1984 ASC
Methodology). On August 1, 2007, the Administrator initiated a series
of public meetings in which informal comment was taken on 17 specific
issues pertaining to the 1984 ASC Methodology. Based in part on public
comment, the methodology proposed by BPA in this notice redefines the
types of capital and expense items includable in ASC, establishes new
data sources from which ASCs are to be derived, and changes the nature
and timing of BPA's procedures for review of ASC filings by utilities
participating in the REP. This notice also contains detailed procedures
for public participation in the consultation proceeding.
This consultation proceeding is intended to facilitate the
compilation of a full record upon which the Administrator will base his
decision for a final ASC Methodology. Although preliminary informal
comments have already been made by some groups and members of the
public, this notice formally solicits public comment. With
[[Page 7271]]
the issuance of this proposal, BPA welcomes different approaches, new
ideas and other types of feedback from interested parties. This
proposal was developed with guidance from public workshops and is meant
to provide a foundation that will facilitate further ideas and
approaches.
In order to participate in the REP during FY 2009, a Pacific
Northwest utility must notify BPA of its intent to participate by
February 22, 2008. A utility also must submit an ASC filing (an
Appendix 1) to BPA by March 3, 2008, or BPA will use the corresponding
Appendix 1 from its WP-07 Supplemental Power Rate Adjustment Proceeding
as the base filing to determine the utility's ASCs for FY 2009. During
the comment period on the proposed ASC Methodology, interested parties
will have the opportunity to participate in an expedited process for
determining exchanging utilities' ASCs for FY 2009 based on the
proposed methodology. In addition to the comments submitted, BPA
expects to learn through this expedited process where improvements or
changes to the proposed methodology can be made. Workshops will be held
during the comment period to help facilitate feedback and explore
different ideas. BPA strives to develop, in concert with the region, an
ASC Methodology that will be legally sustainable, efficient, and
durable over time.
ADDRESSES: Interested members of the public may make written comments
between February 8, 2008, and May 2, 2008. Comments must be received by
5 p.m., Pacific Prevailing Time, on the specified date in order to be
considered in the Record of Decision for the ASC Methodology, which
will be submitted to FERC for interim and final approval. BPA will also
post written comments online. Written comments may be made as follows:
online at BPA's Web site: https://www.bpa.gov/comment, by mail to: BPA
Public Affairs, DKE-7, P.O. Box 14428, Portland, OR 97293-4428, or by
facsimile to 503-230-3285. Please identify written or electronic
comments as ``2008 ASC Methodology.'' Information and comments received
by BPA concerning the proposed ASC Methodology will be posted at http:/
/www.bpa.gov/corporate/Finance/ascm.
FOR FURTHER INFORMATION CONTACT: Ms. Michelle Manary, Manager,
Residential Exchange Program--FE-2, P.O. Box 3621, Portland, OR 97208.
Ms. Leslie M. Dimitman, Paralegal Specialist, Office of General
Counsel, LP-7, P.O. Box 3621, Portland, OR 97208. Interested persons
may also call Ms. Dimitman at 503-230-5515, or the general BPA toll-
free numbers 800-282-3713 (answered Monday through Friday 6:30 a.m. to
5 p.m.) or 866-879-2303 (answered by voice-mail).
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Background
II. The Proposed Average System Cost Methodology
I. Background
A. Relevant Statutory Provisions
Section 5(c)(1) of the Northwest Power Act, 16 U.S.C. 839c(c)(1),
provides that BPA shall acquire certain amounts of power offered for
sale to BPA by a Pacific Northwest electric utility at the average
system cost of the utility's resources in each year. In exchange, BPA
shall offer to sell ``an equivalent amount of electric power to such
utility for resale to that utility's residential users within the
region.'' \1\ Id. Sales to the utility may not be restricted below the
amount of power acquired from the utility. 16 U.S.C. 839c(c)(6). Under
this ``residential exchange,'' there is generally no power transferred
either to or from BPA.\2\ The ``equivalent amount of electric power''
exchanged by BPA with the participating utility is priced at the same
rate as that for general requirements sales to BPA's preference
customers (the ``Priority Firm or PF rate''), subject to adjustment
pursuant to section 7(b)(2) of the Northwest Power Act (the ``PF
Exchange rate''). See 16 U.S.C. 839e(b)(1)-(3). By establishing the
REP, Congress intended to address the issue of wholesale rate disparity
that can exist between BPA's preference customers and investor-owned
customers. Because power sold by BPA to exchanging utilities must be
treated as resold to the participating utility's residential consumers
within the region, ``wholesale rate parity'' is achieved. This
wholesale rate parity is the first attribute of the REP.
---------------------------------------------------------------------------
\1\ The exchange was set equal to 50 percent of a participating
utility's qualifying residential and small farm load as of July 1,
1980, and increased in equal annual increments to 100 percent of
such load over 5 years. See 16 U.S.C. 839c(c)(2).
\2\ Section 5(c)(5) allows BPA to acquire an ``equivalent amount
of electric power from other sources to replace power sold to [a
participating] utility,'' if the cost of such replacement
acquisition is less than the applicable ASC. Implementation of this
provision may result in actual power sales to the exchanging
utility.
---------------------------------------------------------------------------
In contrast, the amount paid by BPA to the participating utility is
not a conventional wholesale power rate. Section 5(c)(1) of the
Northwest Power Act states that BPA is to pay ``the average system cost
of that [exchanging] utility's resources.'' 16 U.S.C. 839c(c)(1).
Section 5(c)(7) of the Northwest Power Act gives BPA's Administrator
the discretionary authority to determine ASC on the basis of a
methodology to be established in consultation proceedings. 16 U.S.C.
839c(c)(7). The only express statutory limits on the Administrator's
authority are found in sections 5(c)(7)(A), (B) and (C) of the Act. 16
U.S.C. 839c(c)(7)(A), (B) and (C).
Generally, the BPA PF rate has been lower than participating
utilities' ASCs under the 1984 ASC Methodology. The resulting monetary
benefits BPA paid to participating utilities, or ``net cost of the
exchange,'' is the second attribute of the REP. As noted above, the REP
is not a conventional power transaction. System schedulers do not
dispatch the exchange; line losses are not incurred. The power purchase
and sale concept was created by Congress for BPA ratemaking purposes.
See 16 U.S.C. 839e(b)(1).\3\ Practically speaking, the purpose of the
REP is to exchange costs for the benefit of the residential and small
farm ratepayers of participating utilities. When the BPA PF Exchange
rate is lower than a participating utility's ASC, BPA pays the net cost
to that utility. However, when the PF Exchange rate is higher than the
ASC, i.e., when the net cost of the exchange is negative, BPA has
previously provided the utility a unilateral right to ``deem'' its ASC
equal to the PF rate, so that no payment flows from the utility to
BPA.\4\
---------------------------------------------------------------------------
\3\ The outcome of this consultation proceeding will not change
the way in which BPA establishes rates under section 7 of the
Northwest Power Act. The resource concept was devised by Congress to
allocate the benefits and costs of the Federal Base System among
competing classes of BPA customers. However, the resource concept
should not obfuscate the nature of the REP as a transfer payment
from BPA to the participating utilities.
\4\ However, BPA has historically kept an account of such unpaid
``deemer'' amounts, which must be paid before the utility can
receive positive REP benefits.
---------------------------------------------------------------------------
Furthermore, Northwest Power Act section 5(c)(4), 16 U.S.C.
839c(c)(4), recognizes that BPA's PF rate, insofar as it applies to the
REP, may carry one or more ``supplemental rate charges'' after July 1,
1985, due to implementation of section 7(b)(3) of the Northwest Power
Act. 16 U.S.C. 39e(b)(3). Were this to occur and cause the PF Exchange
rate to exceed a participating utility's ASC, that utility has the
statutory right to terminate its participation in the REP. 16 U.S.C.
839c(c)(4).
The monetary benefits of the REP must be passed through directly to
the participating utilities' residential and small farm consumers in
accordance with section 5(c)(3) of the Northwest Power Act, 16 U.S.C.
839c(c)(3), guarding against the possibility that the
[[Page 7272]]
utility might set retail residential rates that counteracted the
benefits of the REP. In addition, it is incumbent upon BPA to establish
an ASC methodology that ensures that the net cost of the exchange does
not exceed the limits established by Congress in the Northwest Power
Act. See 16 U.S.C. 839c(c)(7)(A), (B) and (C).
The ASC methodology must also be designed so that BPA does not
become the ``deep pocket'' to which participating utilities may shift
excessive or improper resource costs. The ASC methodology should give
participating utilities an incentive to minimize their costs.
Otherwise, BPA may not be able to satisfy the requirement of section
7(a) of the Northwest Power Act that its rates recover its total
revenue requirement. BPA is a self-financing government agency, which
must recover its costs through rates for sales of electric power and
energy.
B. Average System Cost Methodology Background
The first ASC Methodology was developed in consultation with the
region in 1981. See 48 FR 46,970 (Oct. 17, 1983). It was later revised
in 1984. See 49 FR 39,293 (Oct. 5, 1984); see also PacifiCorp v.
F.E.R.C., 795 F.2d 816 (9th Cir. 1986). The 1984 ASC Methodology has
been in effect since that time. In the mid-1990s, BPA and its
participating ``Utilities'' \5\ agreed to a number of settlements that
provided for payments to each Utility through the remaining years of
the Residential Purchase and Sale Agreements (RPSA) that implement the
REP. Because these settlements did not require the participating
utilities to submit ASC filings, BPA temporarily suspended its ASC
review process.
---------------------------------------------------------------------------
\5\ ``Utility'' is used here as a defined term: the investor-
owned utility or consumer-owned utility that is a Regional Power
Sales Customer that has executed a Residential Purchase and Sale
Agreement.
---------------------------------------------------------------------------
Prior to BPA's WP-02 power rate proceeding, BPA sought to resolve
REP disputes by offering REP Settlement Agreements (Settlement
Agreements) to regional investor-owned utilities. Under these
Agreements, BPA would provide the participating utilities 1,000 aMW of
actual power and 900 aMW of financial benefits for the FY 2002-2006
period, and 2,200 aMW of benefits for FY 2007-2011. Power sales were
made at the Residential Load (RL) Firm Power Rate. Financial benefits
were calculated based on the difference between BPA's RL rate and a
forecast of market prices.
The Settlement Agreements were challenged in the U.S. Court of
Appeals for the Ninth Circuit. On May 3, 2007, the Court held that the
Settlement Agreements executed by BPA and the investor-owned utilities
were inconsistent with the Northwest Power Act. See Portland General
Elec. Co. v. Bonneville Power Admin., 501 F.3d 1009 (9th Cir. 2007). As
a result of the Court's decision, BPA must be prepared to resume the
REP by offering RPSAs to its Utility customers. In addition to the
RPSAs, BPA is conducting this consultation proceeding to revise the ASC
Methodology concurrent with a section 7(i) rate proceeding to consider
revisions to the Section 7(b)(2) Legal Interpretation and Section
7(b)(2) Implementation Methodology, implement the section 7(b)(2) rate
test, and develop rates consistent with the Court's remand in a related
case. See Golden NW Aluminum, Inc. v. Bonneville Power Admin., 501 F.3d
1037 (9th Cir. 2007).
C. The Current Average System Cost Methodology
Under the 1984 ASC Methodology, utilities file with BPA ``Appendix
1'' forms containing cost information based on rate orders from state
utility commissions or consumer-owned utility governing bodies. BPA
reviews each Appendix 1 for conformance with criteria specified in the
Methodology. See 18 CFR 301.1. Appendix 1 filings are subject to review
for 210 days from the start of the relevant exchange period, which is
triggered by a change in retail rates. Not later than 80 days after a
Utility files a new Appendix 1, Regional Power Sales Customers or their
designee may submit written challenges to costs included in the
Utility's Contract System Costs. Not later than 90 days following the
date the Utility files its revised Appendix 1, BPA mails to the Utility
and all parties a list of issues or challenged costs concerning the
Utility's revised Appendix 1 and requesting comments from all parties.
Written comments on the issues list from all parties are due 30 days
after the issue list is filed. Parties may submit cross-comments in
response to comments on the issues list up to 15 days after the written
comments are submitted. Parties may request oral argument before the
Administrator or the Administrator's designee up to 150 days after a
Utility files a new Appendix 1. BPA also has the right under the 1984
ASC Methodology to issue a notice to parties requesting comments on
costs that had not been challenged previously, on Contract System
Loads, and other issues not raised previously. Comments from parties on
such notice are due 150 days after a Utility files a new Appendix 1.
Written cross-comments in response to comments on the BPA notice are
due 165 days after a Utility files a new Appendix 1.
If BPA grants a request for oral argument, it is presented up to
180 days after a Utility files a new Appendix 1. BPA must issue a final
determination on the revised Appendix 1 no later than 210 days after a
Utility files a new Appendix 1.
Discovery is another component of the 1984 ASC Methodology. BPA can
request data from a Utility any time during the 210-day review period.
The Utility is required to respond within 30 days of receiving the data
request. In addition, parties to the ASC review can submit data
requests up to 40 days after the Utility files its revised Appendix 1.
The Utility must respond within 65 days after the Utility files its
revised Appendix 1.
Consumer-owned utilities may execute RPSAs for participation in the
REP. Because consumer-owned utilities are not regulated by the state
commissions in the Pacific Northwest, and because they are not required
to make FERC Form 1 filings, preparation and review of ASC filings is
more burdensome for all parties concerned. The difficulty in the
preparation and review of ASC filings has been a major cause of
disputes between BPA and participating consumer-owned utilities and
became one of the issues leading BPA and the consumer-owned utilities
to settle out their REP participation in the late 1980s.
D. BPA and Customer Concerns With the 1984 ASC Methodology
The reliance on state regulatory agencies to determine the level of
costs included in the ASC of a participating Utility under the 1984 ASC
Methodology, known as the ``jurisdictional costing approach,'' has
resulted in a long, burdensome, expensive and often contentious review
process that many BPA customers said could be improved and streamlined.
The 210-day review period for each ASC filing under the current
methodology means that BPA and its customers are almost always
reviewing an ASC filing. Given the tremendous advancement in
information and communication technology (ICT) since the early 1990s,
the review process and implementation costs can be reduced
substantially through use of electronic filings, e-mail and other
aspects of ICT without changing the existing ASC Methodology. However,
BPA believes that further efficiencies in the ASC filing and review
process could be obtained if BPA were to adopt a new
[[Page 7273]]
framework for obtaining the data required for an ASC filing.
One issue related to the ``jurisdictional costing approach'' that
has not changed since REP disputes were addressed through settlements
is the volume of utility rate orders. Because any commission-ordered
change in retail rates triggers a new ASC filing under the 1984 ASC
Methodology, BPA and its customers could be faced with requirements to
review several ASC filings a year for each investor-owned utility
participating in the REP because of adjustment clauses and tracker
filings in each state where the Utility provides retail electric
service to customers.
BPA is mindful of the difficulty in preparing ASC filings for
consumer-owned utilities that may want to participate in the REP and
hopes that the proposed methodology will ease the burden of preparing
and reviewing Appendix 1 filings.
E. Public Participation in the Consultation Proceeding
This consultation proceeding is intended to facilitate the
compilation of a full record upon which the Administrator will base the
decision to establish the ASC Methodology. Preliminary informal
comments have already been submitted by groups, including investor-
owned utilities, state regulatory agencies and consumer-owned utility
customers. This notice solicits a new round of formal comments from
interested members of the public.
Interested members of the public may make written comments between
February 8, 2008 and May 2, 2008. Comments must be received by 5 p.m.,
Pacific Prevailing Time, on the specified date in order to be
considered in the Record of Decision for the ASC Methodology. BPA will
also post written comments online. Written comments may be made as
follows: Online at BPA's Web site: www.bpa.gov/comment, by mail to: BPA
Public Affairs, DKE-7, P.O. Box 14428, Portland, OR 97293-4428, or by
facsimile to 503-230-3285. Please identify written or electronic
comments as ``2008 ASC Methodology.'' Information and comments received
by BPA concerning the proposed ASC Methodology will be posted at http:/
/www.bpa.gov/corporate/Finance/ascm.
After the written comment stage, an opportunity will be provided
for oral presentations before the Administrator, which will be
transcribed for inclusion in the record. The date, time, and location
of oral presentations will be specified in a future communication. Only
those persons who participate in the written comment stage of the
consultation will have the option of making an oral presentation before
the Administrator. During any stage of the proceeding, negotiated
resolutions of issues raised by BPA or by commenters may be
incorporated into the record by means of written stipulations.
After completion of the foregoing proceedings, the Administrator
will issue a Record of Decision on the revised ASC Methodology. The
revised ASC Methodology will then be submitted to the Federal Energy
Regulatory Commission for review and approval.
II. The Proposed Average System Cost Methodology
A. Introduction
The revised methodology proposed by BPA in this notice is intended
to implement the Northwest Power Act, help alleviate the administrative
burden and expense associated with the jurisdictional approach to ASC
determinations, and to reflect changes in the organization and
operation of the electric utility industry since the 1984 ASC
Methodology was approved. In preparing this proposal, BPA took into
account the issues and concerns raised by parties during workshops held
in August through November of 2007. Although BPA is proposing a number
of broad changes to the 1984 ASC Methodology, the proposal is not a
complete reconstruction of the previous 1984 ASC Methodology. Several
portions of the proposal reflect features from the 1984 ASC Methodology
that remain viable in today's environment.
BPA anticipates that there will be a wide variety of comments on
the proposed ASC Methodology, and also expects that comments will raise
issues that may not have been apparent to BPA. BPA stresses the
importance of written comments that precisely state each commenter's
position on issues of concern, whether the comments be positive or
negative, so that a complete record can be compiled. Numerical analyses
and examples will be of particular assistance to BPA in developing a
revised ASC Methodology. BPA also welcomes negotiations and possible
settlements of issues.
B. The Uniform Cost Approach to Determining Average System Cost Under
the Proposed Methodology
Both the 1981 and 1984 ASC Methodologies used the jurisdictional
costing approach for ASC determinations. As noted above, using the
jurisdictional cost approach as the data source for the ASC
calculations has proven to be inefficient, cumbersome, and extremely
contentious. BPA therefore is proposing to not use a jurisdictional
costing approach for the revised ASC Methodology. In its place, BPA is
proposing to use a data source that is uniform and that facilitates
ease of administration for all parties. Such data can be found for
investor-owned utilities in the FERC Form No. 1 (Form 1), a compilation
of financial and operating information prepared annually in accordance
with the Commission's Uniform System of Accounts for Public Utilities
and Licensees. See 18 CFR 101 (2007). As explained more fully below,
consumer-owned utilities that wish to exchange with BPA will be
required to submit equivalent information to establish their ASCs.
Under the proposed ASC Methodology, the Utility may include in its
ASC only actual costs documented in its Form 1 or equivalent, with
limited exceptions. These exceptions include the following: First,
equity return for investor-owned utilities will be determined in
accordance with procedures described later in this notice; second,
Federal income taxes will be included at the marginal Federal income
tax rate; third, the Form 1 does not always contain enough information
or level of detail to allow BPA to determine whether costs are
includable in ASC, thus requiring supplemental information; and fourth,
BPA will require utilities that do not file a Form 1 with FERC to
submit audited financial data in a format comparable to the Form 1 and
a detailed cost of service analysis prepared by an independent
accounting or consulting firm, approved by the Utility's Regulatory
Body \6\ and used as the basis for setting retail rates currently in
effect.
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\6\ ``Regulatory Body'' is used here as a defined term: A state
regulatory body, consumer-owned utility governing body, or other
entity authorized to establish retail electric rates in a
jurisdiction.
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BPA is proposing an approach for determining a utility's ASC that
is aimed at simplicity, transparency and minimal administrative burden
for all parties. BPA recognizes this may make it difficult to reflect
unique circumstances of individual utilities, which may have an impact
on their ASCs. BPA is open to different types of approaches and
welcomes such suggestions during the comment period.
[[Page 7274]]
C. Procedural Format for ASC Determinations Under Revised ASC
Methodology
1. ASC Determination Process Guidelines
BPA proposes to review each Utility's filed ASC in a simplified
administrative process. This process will commence during the period
prior to BPA filing an initial proposal for a change in wholesale power
rates, referred to as the Review Period. An investor-owned utility
would submit a ``base period ASC'' to BPA using data from the prior
year's Form 1 on or before May 1 of each year. For Utilities not
required to submit a Form 1 to FERC, the base period ASC would be
determined from a filing similar in format to a Form 1. The Utility's
base period ASC will be projected by BPA to determine the ASC for the
BPA rate period.\7\ Escalating the cost data used to determine the base
period ASC to be consistent with the test year(s) of the BPA rate
proposal addresses many issues of temporal consistency between ASCs and
BPA's PF Exchange rate. As a general matter, once the Administrator
determines the ASC for each Utility, the ASC will remain at that level
for the term of the BPA rate period.
---------------------------------------------------------------------------
\7\ BPA will forecast the utility's ASC for an additional four
years as required for the section 7(b)(2) rate test in BPA's
wholesale power rate adjustment proceedings.
---------------------------------------------------------------------------
Proposed changes to established ASCs would only be allowed under
two specific conditions. First, the ASC may be adjusted in the event a
Utility acquires a new service territory or relinquishes all or a
portion of its service territory. A second adjustment may be made to
account for major new resource additions, purchases, retirements or
sales. In the event that a Utility has a resource that is projected to
come on-line or be purchased and used to meet that Utility's retail
regional load during the BPA rate period, the Utility will submit two
ASC filings: (1) One conforming to the Form 1 described above, and (2)
a second filing that incorporates the costs associated with the new
resource based on the expected commercial operation date of the new
resource or, for resource purchases, the date the sale is completed and
the costs associated with the purchased resource used to meet that
utility's regional retail load. In addition to including the estimated
capital and operating costs of the new resource, the Utility must also
estimate the changes in purchased power expense, sales for resale
credit and other costs based on the additional generation provided by
the new resource. Because the commercial on-line dates of power plants
often change during the construction process, BPA will not adjust the
Utility's ASC until the new generating resource begins commercial
operation.
For a major resource used to meet the Utility's regional retail
load that is projected to be unable to serve load, retired or sold
during the BPA rate period, BPA proposes that the Utility make two ASC
filings: (1) One conforming to the Form 1 described above, and (2) a
second filing that excludes the costs associated with the retired or
sold resource based on the expected retirement or closing date of the
resource. In addition to including the reduction in estimated capital
and operating costs of the retired or sold resource, the Utility must
also estimate the changes in purchased power expense, sales for resale
credit and other costs based on the generation formerly provided by the
retired or sold resource. BPA proposes not to adjust the Utility's ASC
until the official retirement or transfer date of the generating
resource.
BPA proposes that all Utilities be required to submit ASC filings
using BPA's electronic template (Appendix 1) \8\ on or before May 1 of
every year. Several areas of the ASC filing template require additional
data and/or analyses. The additional data/analyses must also be in
electronic format and submitted at the same time as the Appendix 1
template. The filing, along with the additional data and support, will
be made available to BPA customers and other parties for review through
BPA's external Web site. Each filing may be reviewed by BPA or its
designee to determine whether the costs are consistent with Generally
Accepted Accounting Principles for electric utilities and consistent
with the ASC Methodology.
---------------------------------------------------------------------------
\8\ Appendix 1 refers to the appendix to both the current and
proposed ASC methodology containing the form on which the exchanging
utility reports its Contract System Costs and other information
required for the calculation of ASC.
---------------------------------------------------------------------------
BPA envisions that this approach will reduce the time,
administrative burden and cost to BPA, the Utility, other BPA customers
and other interested parties without significantly affecting the
accuracy of the ASC determination when compared to the more cumbersome
process required under the 1984 ASC Methodology. BPA proposes that ASC
determinations prior to BPA's rate cases will replace the multiple
determinations in each year required under the 1984 ASC Methodology for
each jurisdiction in which a Utility provides retail residential
service upon each change in retail rates.
The revised ASC Methodology has characteristics similar to
ratemaking based on an historical test year incorporating end-of-year
data. Each Utility would be permitted to include the same types of
costs in ASC based on actual data from the same calendar-year period.
It is uniform in contrast to the 1984 ASC Methodology, which relied on
data from retail rate proceedings throughout the Northwest, each using
different ratemaking methodologies and test years.
Although the numbers included in Form 1 accounts by Utilities will
help expedite ASC reviews, Utilities' ASC filings will continue to be
scrutinized by BPA, its customers and other participants in the ASC
review process. BPA has a statutory responsibility to ensure that all
improper costs are excluded from ASCs. Each ASC filing must contain a
statement, signed by a senior officer of the Utility, stating that all
data submitted by the Utility were compiled in strict compliance with
the Commission's Uniform System of Accounts, the ASC Methodology, and
Generally Accepted Accounting Principles, and are consistent with
applicable orders and policies of their Regulatory Body. For Utilities
not required to submit a Form 1, the attestation will state that the
data were compiled in strict compliance with the Utility's financial
statements, the ASC Methodology, and policies and orders from the
Utility's Regulatory Body. BPA proposes that any filing that does not
contain this attestation will not be accepted by BPA for determination
of an ASC.
BPA invites and welcomes comments on alternative sources of
verifiable data for use in determining ASC. Such comments should
contain detailed explanations of the verification safeguards inherent
in any proposed alternative as well as procedural alternatives.
2. Transition Implementation of the REP
BPA hopes to begin the implementation of the REP for eligible
utilities on October 1, 2008. To do so, BPA must negotiate and execute
new RPSAs with Utilities, establish a revised ASC Methodology, and
establish ASCs under the revised Methodology. As noted below, BPA also
intends to implement the proposed ASC Methodology in an expedited ASC
review during the spring of 2008 in order to identify any problems that
might arise in implementing the Methodology. The results of the
expedited ASC review will be used as a starting point for the
determination of final ASCs for FY 2009. The expedited
[[Page 7275]]
ASC review will be implemented as follows.
After publication of the proposed ASC Methodology, a Utility
intending to participate in the REP beginning October 1, 2008, must
notify BPA of its intent by February 22, 2008. If a Utility fails to
notify BPA of its intent to participate in the REP in FY 2009 by
February 29, 2008, the Utility will be ineligible to receive any REP
benefits during the FY 2009 rate period. A Utility must file its
Appendix 1 based on the proposed ASC Methodology with BPA by March 3,
2008. If it fails to do so, BPA will rely on the Appendix 1 for the
Utility included by BPA in its WP-07 Supplemental Rate Proposal to
determine ASCs for FY 2009. BPA will provide electronic access to the
Appendix 1 filings on March 4, 2008, to all Regional Power Sales
Customers and other interested parties. BPA will review all Appendix 1
filings concurrently in an expedited public process. Interested parties
will have the opportunity to intervene in BPA's review. Petitions to
intervene must be filed with BPA by March 11, 2008. Data requests must
be submitted by March 14, 2008. BPA will commence discovery workshops
on all Appendix 1 filings on March 26, 2008. BPA and parties will
address and resolve all discovery issues in the workshops. BPA and
parties may electronically file an issue list identifying and providing
full arguments regarding the contested elements of a Utility's Appendix
1 filing by April 10, 2008. The Utility will electronically file, and
other parties may file, a response to the issue lists on April 24,
2008. A second workshop will be held on April 29, 2008, to discuss and
resolve, to the extent possible, the identified issues. BPA will then
review the parties' arguments, rule on such issues, and publish and
electronically serve all parties with a Draft ASC Reports on May 9,
2008. The Utility and parties may file comments on the Draft ASC
Reports by May 23, 2008. After reviewing the comments, the BPA
Administrator will issue Final ASC Reports on June 6, 2008.
After BPA develops the final proposed ASC Methodology, BPA will
file the Methodology with FERC for confirmation and approval. BPA hopes
to receive interim approval of the Methodology on or around September
1, 2008. After FERC approval, BPA proposes to review the ASC
determinations resulting from the expedited ASC review. BPA will
compare the proposed ASC Methodology provisions with the FERC-approved
Methodology. If there are no differences between the data included in
the Utilities' initial Appendix 1s (or the Appendix 1 filings developed
by BPA for the WP-07 Supplemental Rate Proposal) and the Appendix 1s to
be filed under the final Methodology, the Utilities' initial Appendix
1s (or the default WP-07 Supplemental Appendix 1s) can be used for the
Utilities' final ASC determinations. If the Appendix 1s are the same
but the substantive criteria of the Methodology have changed from the
initial proposed Methodology, BPA will recalculate each Utility's ASC
by reviewing the initial Appendix 1 and applying the final Methodology
criteria. Because the Utility's initial Appendix 1 will have been
reviewed in the expedited review, BPA will conduct an abbreviated
review with all interested parties to ensure that the Utilities' ASCs
comply with the FERC-approved Methodology. If BPA determines that the
ASCs comply, BPA will establish the ASCs as the Utilities' final ASCs
for FY 2009.
BPA also must plan for the establishment of each Utility's ASC for
FY 2010-2011. Under the proposed ASC Methodology, except for the
initial one-year Exchange Period under the revised Methodology, and the
second Exchange Period for FY 2010-2011, a Utility must file an
Appendix 1 by May 1 of each year. If a Utility wishes to participate in
the REP in the second Exchange Period for FY 2010-2011, it must file an
Appendix 1 using 2007 data by July 1, 2008. If a Utility fails to file
an Appendix 1 by July 1, 2008, the Utility will receive no REP benefits
for the FY 2010-2011 period. After receiving all exchanging Utilities'
Appendix 1s by July 1, 2008, BPA will promptly publish a schedule for
review of the filings. Although BPA hopes to complete this review using
the ASC review schedule contained in the ASC Methodology, BPA may issue
a schedule different from the prescribed schedule in order to ensure
that ASCs for FY 2010-2011 are established in time to be incorporated
in BPA's FY 2010-2011 wholesale power rate initial proposal. After
completing its ASC review process, BPA will establish ASCs for FY 2010-
2011. If FERC approval of the ASC Methodology is subsequent to this ASC
review, BPA will compare the Methodology used to calculate the ASCs
with the FERC-approved Methodology. BPA will conduct an abbreviated ASC
review will all interested parties to ensure that Utilities' ASCs
comply with the final Methodology. If BPA determines that the ASCs
comply, BPA will establish the ASCs as the Utilities' final ASCs for FY
2010-2011.
D. Invoicing and Payment Using Actual Residential Load
Although not a part of the ASC Methodology, BPA proposes to
continue the contractual requirement that Utilities invoice BPA monthly
based on actual eligible residential and small farm loads. A Utility's
monthly REP payment is determined by subtracting the Utility's BPA PF
Exchange Rate \9\ from the Utility's ASC, and then multiplying the
result by the Utility's actual eligible monthly residential and small
farm load.
---------------------------------------------------------------------------
\9\ BPA is proposing in the WP-07 Supplemental Rate Proceeding
to develop either Utility-specific PF Exchange rates or a PF
Exchange rate with Utility-specific supplemental rate charges. In
either case, the applicable BPA rate will be determined specifically
for each Utility. This rate determination methodology requires that
BPA know during the rate proceeding which Utilities intend to
participate in the REP.
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E. Treatment of Certain Resource Costs Under the Proposed Average
System Cost Methodology
1. Transmission Investments and Related Expenses Included in Contract
System Costs
Transmission investments and expenses were included in ASCs under
BPA's 1981 ASC Methodology. The 1981 ASC Methodology was established
pursuant to a negotiated settlement, agreed to by all parties. The
Administrator's 1981 ASC Methodology Decision, at 1-2, explains the
process by which most issues, including the propriety of adding
transmission costs to ASC, were resolved through a negotiated
settlement in the first consultation proceeding. The Commission granted
final approval to the 1981 ASC Methodology on October 17, 1983. See
Sales of Electric Power to Bonneville Power Admin., Methodology and
Filing Requirements, 48 FR 46,970 (Oct. 17, 1983).
In the 1984 ASC Methodology, BPA included ``all existing
transmission, as defined in the Commission Uniform System of Accounts,
in service as of July 1, 1984 * * *'' and ``[f]or transmission plant
commencing service after July 1, 1984, transmission plant costs that
can be exchanged are limited to transmission facilities that are
directly required to integrate resources to the transmission grid.''
\10\ The Commission granted final approval to the 1984 ASC Methodology
on October 5, 1984, which continued to allow certain transmission costs
in ASC. See Methodology for Sales of Electric Power to Bonneville Power
Administration, 49 FR 39,293 (October
[[Page 7276]]
5, 1984), FERC Statutes and Regulations ] 30,601.
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\10\ 1984 Administrator's Record of Decision, Average System
Cost Methodology at 42.
---------------------------------------------------------------------------
Even though the 1984 ASC Methodology allowed all transmission prior
to 1984 but only a portion of it after 1984, upon further consideration
BPA believes transmission should be included in the calculation of
utilities' ASCs. One of the main reasons for this conclusion is that
the exclusion of the transmission component of electricity production
and delivery may introduce an inequity between Utilities that develop
resources close to their service territory and those that develop
geographically distant resources. Therefore, BPA proposes that the cost
of resources should include all costs associated with the delivery of
power to the Utility's load centers.
Furthermore, since implementation of the 1984 ASC Methodology and
its approval by the Commission, the electric utility industry has
undergone significant changes in structure, specifically, the
development of wholesale power markets, creation of regional
transmission organizations (RTOs) and the separation of generation and
transmission functions of vertically integrated electric utilities
mandated by Commission Order 888, which was issued in 1996. In 1999,
BPA administratively separated its power and transmission functions to
voluntarily comply with the Commission's order for investor-owned
utilities to separate generation and transmission. Consequently, BPA
now develops separate rates for power and transmission.
As a result of this change in industry structure, electric
utilities have a variety of ways to acquire generation to serve their
retail load. For example, utilities can: (1) Rely on wholesale power
markets; (2) build centralized generation units close to the fuel
source; or (3) build the generation close to the load center and
transport the fuel source (e.g. coal by rail). In addition, many large
power plants are owned by more than one utility. This diversity in the
method of acquiring electric generating capacity to serve retail load
means that excluding transmission costs from the ASC calculation would
have adverse effects on Utilities. Exclusion of the transmission
component of electricity production and delivery would introduce an
inequity between Utilities that develop resources close to their
service territory and those that develop geographically distant
resources. In summary, BPA proposes that the cost of resources should
include the cost of transmission used to deliver resources to retail
load.
2. Treatment of Conservation Costs
In the 1984 ASC Methodology, the Administrator determined which
conservation costs could be included in ASCs. The determinations ``were
case specific, based on the information provided by exchanging
utilities.'' \11\ Generally, the 1984 ASC Methodology allows Utilities
to include only the costs of ``measures for which power is saved by
physical improvements or devices. Advertising, promotion and audit
expenses are not resource costs and therefore are not includable in the
ASC.'' \12\
---------------------------------------------------------------------------
\11\ 1984 ASC Methodology Record of Decision at 73.
\12\ Id. at 74
---------------------------------------------------------------------------
BPA proposes to continue with the 1984 ASC Methodology's exclusion
of advertising and promotion costs, except that the revised Methodology
will allow Utilities to include the cost of energy audits. BPA proposes
to allow energy audits because the only way to determine if a
conservation program or measure will be cost effective is through an
analysis or ``audit'' of the facility where the conservation measure
will be installed. Some items such as energy efficient light bulbs are
cost effective in almost any location. Others, like insulation, energy
efficient windows or HVAC upgrade/replacements must be analyzed in
advance to see if the measure is cost effective. In many ways, the
audit is a form of or extension to the Utility's least-cost plan. If
the audit is not done before the measure is installed, the funds could
be used on a measure that is not cost effective. For this reason, BPA
believes it is reasonable to allow the costs of audits in the ASC
calculation.
3. Treatment of Oregon's Public Purpose Charge Related to the
Acquisition of Conservation and Renewable Resources
Oregon's Public Purpose Charge (OPPC) was established in 1999 with
passage of Oregon's electricity restructuring law, Senate Bill 1149.
See generally, Or. Rev. Stat. Sec. 757.612 (2005). The OPPC was
established to ``fund new cost effective local energy conservation, new
market transformation efforts, the above-market costs of renewable
energy resources and new low income weatherization.'' Id. at Sec.
757.612(2)(a). The OPPC is set at 3 percent of total retail sales of
electricity for PacifiCorp-Oregon, Portland General Electric (PGE) and
Idaho Power-Oregon. Id. The OPPC applies to consumer-owned utilities
only if they allow direct access to any class of their customers. Id.
At this time, BPA is not aware of any consumer-owned utilities that are
participating in OPPC program. The OPPC replaces the conservation/DSM
programs PGE, PacifiCorp-Oregon and Idaho Power-Oregon operated before
Oregon SB 1149. When the OPPC was implemented by the utilities, the
OPUC was directed to remove the costs of OPPC-like programs from retail
rates. Id. at Sec. 757.612(3)(g).
The OPPC was implemented on March 1, 2002, for PGE and PacifiCorp-
Oregon, and in 2006 for Idaho Power-Oregon. Distribution of the OPPC
funds are made monthly by the utilities to the following organizations
in the following percentages:
Energy Trust of Oregon (ETO)--73.8%
Education Service Districts (ESD)--10.0%
Oregon Housing and Community Services (OHCS)--16.2%
PGE, PacifiCorp and Idaho Power do not show the OPPC on their
financial statements or Form 1s. The utilities treat the revenue and
expense as a direct pass-through. Accounting records are available from
the utilities showing the revenue received and the payments made to the
three recipient organizations. SB 1149 states that the OPPC funds be
allocated in the following manner:
New cost-effective conservation and market transformation--63%
Above market cost of renewable energy resources--19%
Low-income weatherization--13%
Low-income bill payment assistance--5%
The 1981 and the 1984 ASC Methodologies did not address the cost
treatment of charges like the OPPC. A key attribute of the OPPC has
been that it effectively replaces the Utility's conservation program,
which is typically included as part of a Utility's base rates. Because
of this unique feature, BPA proposes that the OPPC is an alternative
form of acquiring conservation and renewable resources, and therefore
should be considered in determining ASC. In the same way that some
utilities build thermal resources and others purchase power from the
market, BPA proposes that the OPPC is a similar method of acquiring
conservation and renewable resources. Another way of looking at the
OPPC is as an outsourcing arrangement. While some utilities have their
own conservation departments and programs, Oregon investor-owned
utilities are effectively required to ``outsource'' their conservation
activities to the ETO, OHCS and ESDs. BPA needs to have the right to
review and audit the costs and programs of the organizations that
receive OPPC funds in order to
[[Page 7277]]
determine the portion of the Utility's costs that are excludable from
their ASC. If an OPPC-recipient organization denies BPA the right to
review and audit its costs and programs, then BPA will not include such
costs in the Utility's ASC calculation. BPA will review the OPPC costs
and functionalize the costs using the same procedure as used in
reviewing Utility conservation costs.
4. Treatment of Return on Equity and Federal Income Taxes
In the Federal Register Notice for the 1984 ASC Methodology
proposal, BPA stated that ``[i]n developing an ASC methodology the BPA
Administrator has considerable discretion in deciding whether to permit
inclusion of an equity return allowance and, if so, how that component
is to be determined.'' \13\ The Administrator's discretion was affirmed
by the Commission in its order approving the 1984 ASC Methodology.\14\
In the 1984 ASC Methodology, BPA excluded the cost of equity in the ASC
determination in part because of concern that Regulatory Bodies may
increase the allowed return on equity (ROE) to compensate Utilities for
the cost of terminated plants and because ROE is primarily associated
with the default risk of investor-owned utilities. On review, the Ninth
Circuit affirmed BPA's view that ROE be excluded from the ASC
calculation in light of BPA's experience with implementing the program
and its need to avoid abuses. PacifiCorp v. F.E.R.C., 795 F.2d 816, 823
(9th Cir. 1986). In making this finding, though, the Court held that
``[t]he statute itself, however, neither commands nor proscribes these
adjustments in ASC methodology.'' Id. Consequently, the Court noted
that it did not ``sanction any permanent implementation of these
exclusions.'' Id. at 823.
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\13\ 49 FR 4230, 4235 (Feb. 3, 1984).
\14\ 49 FR 39,293, 39,296 (Oct. 5, 1984): Congress chose the
Administrator to determine cost of utility resources. Had the
Congress intended that the Administrator must follow State
commission determinations of a utility's resource costs, it could
have easily included this requirement in the statute or simply left
the Administrator out altogether and let the State commissions
develop the ASC methodology. This was not done. The Administrator
was chosen to develop a methodology to determine ASC, subject to the
Commission's review.
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The 1984 ASC Methodology did not allow ROE in ASCs, but instead
permitted the inclusion of the Utility's long-term cost of debt. BPA
now proposes that ROE should be allowable in ASC. The cost of debt is a
cost of resources and, in the case of investor-owned utilities, the
cost of debt is lowered by the contribution of equity by the company.
Without the spreading of risk to shareholders there would be a
significant increase in the cost of debt. State commissions and rating
agencies require investor-owned utilities to maintain specific capital
structures that affect the company's debt ratings. Therefore, debt
alone is not an adequate reflection of the capital cost of a Utility's
resources. Without an equity component in the cost of capital, a higher
cost of debt is needed to reflect the true cost of financing resources.
BPA finds that enough changes have occurred in the PNW regulatory
environment to reasonably ensure that terminated plant costs will not
be included with allowable costs under the ASC Methodology. First, the
costs of the Pebble Springs nuclear plant that were the basis of the
terminated plant controversy in the mid-1980s have been completely
written off by the utilities involved. Second, Oregon's establishment
of a three-person appointed public utility commission greatly reduces
the chance of improper communications between the Oregon PUC and
utilities. Third, since 1984, Oregon has had a Citizens' Utility Board
(CUB), which monitors the retail rate development of utilities
conducting business in Oregon. CUB reviews retail rates in order to
ensure, among other things, that terminated plant costs are excluded
from such rates. Additionally, increased disclosure and filing
requirements at the commission level make identifying inappropriate
costs much easier. All four state commissions now have requirements
that utilities under their review prepare Integrated Resource Plans.
From these filings, BPA and its customers can likely determine if a
Utility included the costs of terminated plant in its equity
calculation. Thus, the risk that Regulatory Bodies will include
inappropriate costs in the ROE has diminished significantly since 1984.
Because of these changes, and based on BPA's experience in
implementing the ASC, BPA now proposes that Utilities should be allowed
to exchange ROE. In the revised ASC Methodology, BPA is proposing to
allow return on equity as determined by the Regulatory Bodies at a
Utility's most recent commission-approved level. For purposes of
determining return on rate base, the Utility will include the weighted
cost of capital from its most recent rate order. For Utilities with
service territories in more than one state, the Utility shall submit a
weighted cost of capital based on the most recent Regulatory Body rate
orders weighted by rate base in states within the PNW region.
In the 1984 ASC Methodology, BPA did not allow the inclusion of
Federal income taxes in ASC. BPA's rationale stated that ``nothing in
the [Northwest Power] Act or its legislative history requires the
inclusion or exclusion of income taxes in computing the average system
cost of a Utility's resources.'' \15\ The Commission approved BPA's
interpretation, albeit with some reservation because of an apparent
``contradiction'' in the allowance of a proxy for equity returns
elsewhere in the methodology.\16\ On review, the Ninth Circuit was
equally reserved when reviewing the 1984 ASC Methodology. PacifiCorp,
795 F.2d at 823. As with ROE, which was decided in the same opinion,
the Court affirmed BPA's interpretation with the notation that it did
not ``sanction any permanent implementation of these exclusions.'' Id.
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\15\ 1984 Administrator's Record of Decision, Average System
Cost Methodology at 59.
\16\ 49 FR 39,293, 39,297 (Oct. 4, 1984).
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Under the revised ASC Methodology, BPA is proposing to allow
Utilities to exchange the costs of certain taxes through their ASCs.
BPA is proposing this change because it is necessary to have symmetry
between its treatment of ROE and taxes. As noted above, BPA is
proposing to allow the costs associated with equity return as a
resource cost in calculation of ASC. If the cost of Federal income
taxes at the marginal tax rate is not also included, then an investor-
owned utility's cost of resources would be understated. When
calculating the revenue requirement for an investor-owned utility,
Regulatory Bodies typically gross up the cost of equity by the marginal
Federal income tax rate to arrive at the ``after tax'' return. In the
same manner, because BPA is proposing to include ROE as a resource cost
in the ASC Methodology, BPA is also proposing to gross up the equity
component by the Federal income tax rate when determining an investor-
owned utility's weighted cost of capital in ASC.
5. Functionalization of Regulatory Assets and Liabilities in ASC
Regulatory assets and liabilities are expenses, revenues, gains or
losses that would normally be recognized in net income in one period,
but for an order of a Regulatory Body specifying a different recovery
period in retail rates. Regulatory Assets and Liabilities, Accounts
182.3 and 254 in the Commission Uniform System of Accounts, were
established in March 1993 in Commission Order No. 552,
[[Page 7278]]
which established uniform accounting treatment for allowances
associated with the 1990 Clean Air Act. Order No. 552 also dealt more
broadly with accounting for regulatory assets and liabilities for
electric and gas utilities.\17\ Regulatory assets and liabilities were
not addressed in the 1984 ASC Methodology.
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\17\ G. Hahne and G. Aliff, Public Utility Accounting 11-5
(Mathew Binder 2005).
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For investor-owned utilities located in the Pacific Northwest,
regulatory assets and liabilities are a significant portion of the
balance sheet. Examples of costs and revenues that can be deferred and
included as a regulatory asset or liability with Regulatory Body
approval include: fuel costs subject to a power cost adjustment, storm
damage, gains on reacquired debt, deferred compensation plans, stranded
costs, phase-in plans, deferred income taxes, asset retirement
obligations, asset impairment or disposal under Financial Accounting
Standards Board 144, rate case expenses and intervenor funding, buyout
costs for non-utility generation, deferred purchase capacity costs,
deferred demand-side management costs, U.S. Department of Energy
(USDOE) nuclear fuel enrichment clean-up fees, deferred revenue related
to income taxes associated with allowance for funds used during
construction (AFUDC), unamortized loss on reacquired debt, and deferred
return on sales of emission allowances. The above list is only
representative of the deferred costs and revenues that would be found
in a typical Form No.1 or a Regulatory Body rate or accounting order.
There are three major issues for the revised ASC Methodology
relating to treatment of regulatory assets and liabilities. First, how
should regulatory assets and regulatory liabilities be functionalized
between production, transmission, and distribution? Second, for the
production-related assets and liabilities, what rate of return, if any,
should the Utility earn on these items for purposes of determining a
Utility's ASC? And finally, how should the amortization of regulatory
assets and liabilities be handled in the ASC review process?
Functionalization of regulatory assets and liabilities raises
several problems because of the lack of information contained in the
Form 1 concerning the nature of these items. Descriptions of regulatory
assets and liabilities are cryptic at best. Some of the deferred costs
are of a short-term nature, such as power costs, which may be carried
as a deferral for a matter of months. Other costs may be deferred and
amortized 5 years or more, such as costs associated with storm damage
and conservation. The Form 1 provides little or no detail on the length
of the deferral period for each item. Nor does it provide information
on whether the deferred assets and liabilities are included in rate
base by the Utility's Regulatory Body. A brief review of several
regional Regulatory Body rate orders revealed few references to
regulatory assets in the list of items included in rate base. Finally,
the Commission's Uniform System of Accounts does not provide specific
rules for amortization of regulatory assets. Review of the Utilities'
Form 1 filings reveal that some utilities amortize regulatory assets
and liabilities to Accounts 407.3, Regulatory Debits and 407.4,
Regulatory Credits, while others amortize regulatory assets and
liabilities to specific income or expense accounts. For these reasons,
BPA proposes that Utilities must perform a direct analysis and
functionalize all regulatory assets and liabilities to Production,
Transmission, or Distribution/Other. The Utility must provide
documentation supporting its rationale for functionalization of the
regulatory asset or liability. This documentation must consist of
general ledger entries, a description of the item in sufficient detail
to permit BPA to determine the functional nature of the cost, and all
communications on the asset or liability between the Utility, its
Regulatory Body and its external auditor. The documentation must also
show that the asset or liability is included in the Utility's
calculation of rate base approved by its Regulatory Body and the
allowed return or carrying cost. In no case will the amount of
regulatory assets and liabilities allowed in ASC exceed the amount
included in retail rates for the same period by the regional Regulatory
Bodies.
6. Treatment of Cash Working Capital in ASC
Cash Working Capital (CWC) is a component in almost all Regulatory
Body determinations of rate base. Inclusion of CWC as an element of
rate base is consistent with the principle that investors receive a
fair return on investment that is used, useful and devoted to public
service. One definition of CWC as used in regulatory proceedings is:
The average amount of capital provided by investors, over and
above the investment in plant and other specifically measured rate
base items, to bridge the gap between the time expenditures are
required to provide services and the time collections are received
for such services.\18\
\18\ Id. at 5-4.
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Because the 1981 and 1984 Methodologies relied on the
jurisdictional approach, CWC was a part of the Utilities' rate base
calculation in Regulatory Body rate orders. The 1981 and 1984
Methodologies simply set an upper limit on the amount of CWC included
in rate base for the ASC calculation.\19\
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\19\ See 18 CFR 301.1 FN. h.
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Because the revised ASC Methodology proposes to use the Form 1
(which does not include a CWC value) as the basis for data for ASC
filings, BPA believes it is important to include a separate determined
value for CWC in the Utility's rate base calculation for ASC purposes.
While determination of the proper amount of CWC in rate base is often
very controversial, a standard and widely accepted measure is one-
eighth of total O&M costs, less fuel and purchase power costs.\20\ This
one-eighth formula was the cap or maximum amount that BPA allowed for
CWC in the 1984 ASC Methodology.
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\20\ G. Hahne and G. Aliff, Public Utility Accounting 5-5
(Mathew Binder 2005).
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BPA is proposing to use this formula--one-eighth of total
exchangeable O&M costs, less fuel and purchase power costs--for the CWC
value included in the Appendix 1 filing. The details are shown in
Schedule 1A of the revised ASC Methodology template.
7. Single ASC for Multi-Jurisdictional Utilities
Under the 1981 and 1984 ASC Methodologies, BPA used a
jurisdictional approach to determining a Utility's ASC. For Avista,
Idaho and PacifiCorp, Utilities that serve retail customers in more
than one state, reliance on Regulatory Body rate orders for ASC
determinations resulted in separate ASC filings for each state.
Developing ASCs by state for multi-jurisdictional Utilities presents
problems for those utilities because Form 1 filings are prepared on a
total utility basis, and trying to separate and allocate the costs from
the total system to individual states would be burdensome and expensive
for both the Utility and BPA. For this proposal, BPA proposes to
develop a single ASC for each Utility. Because PacifiCorp has service
territories that are outside the Pacific Northwest region, it will be
required to submit an ASC filing based on an allocation of its in-
region resources and costs, based on the individual state results of
operations
[[Page 7279]]
filings PacifiCorp files with each Regulatory Body.
8. Treatment of Purchased Power and Sales for Resale Credit
Purchased power and sales f