[Federal Register Volume 73, Number 26 (Thursday, February 7, 2008)]
[Notices]
[Pages 7270-7279]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-2258]


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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

AGENCY: Bonneville Power Administration (BPA), DOE.

ACTION: Notice; request for comments (BPA File No.: ASCM-08).

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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: http://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.
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    \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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    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\
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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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    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.
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    \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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    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.

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

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

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

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

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

    \15\ 1984 Administrator's Record of Decision, Average System 
Cost Methodology at 59.
    \16\ 49 FR 39,293, 39,297 (Oct. 4, 1984).
---------------------------------------------------------------------------

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

    \17\ G. Hahne and G. Aliff, Public Utility Accounting 11-5 
(Mathew Binder 2005).
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \19\ See 18 CFR 301.1 FN. h.
---------------------------------------------------------------------------

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

    \20\ G. Hahne and G. Aliff, Public Utility Accounting 5-5 
(Mathew Binder 2005).
---------------------------------------------------------------------------

    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 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 5-year 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 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: http://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