Document ID: FERC-2008-1469-0001
Agency: ferc
Document Type: Rule
Title: Sales of Electric Power to the Bonneville Power Administration; Revisions to Average System Cost Methodology
Posted Date: 2008-10-10T04:00Z

[Federal Register: October 10, 2008 (Volume 73, Number 198)]
[Rules and Regulations]               
[Page 60105-60151]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10oc08-4]                         

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 301

[Docket Nos. EF08-2011-000 and RM08-20-000]

 
Sales of Electric Power to the Bonneville Power Administration; 
Revisions to Average System Cost Methodology

September 30, 2008.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Interim rule.

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SUMMARY: The Bonneville Power Administration (Bonneville) has submitted 
for the Federal Energy Regulatory Commission (Commission)'s approval a 
new methodology for determining the average system cost (ASC) of a 
utility's resources under the Pacific Northwest Electric Power Planning 
and Conservation Act (Northwest Power Act). Bonneville requested that 
the Commission revise its regulations to incorporate the new 
methodology and to make the revised regulations effective October 1, 
2008. On an interim basis, the Commission is conditionally revising its 
regulations governing the ASC methodology used by Bonneville in its 
Residential Exchange Program. The Commission also is requesting 
comments on whether, on a final basis, the Commission should approve 
the new ASC methodology proposed by Bonneville.

DATES: Effective date: This interim rule is effective October 10, 2008.
    Applicability date: The initial exchange period begins October 1, 
2008
    Comment date: Comments on the interim rule are due November 10, 
2008.

ADDRESSES: You may submit comments on the interim rule, identified by 
Docket Nos. EF08-2011-000 and RM08-20-000, by one of the following 
methods:
     Agency Web site: http://www.ferc.gov. Follow instructions 
for submitting comments via the eFiling link found in the Comment 
Procedures Section of the preamble.
     Mail: Commenters unable to file comments electronically 
must mail or hand deliver an original and 14 copies of their comments 
to the Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street, NE., Washington, DC 20426. Please refer 
to the Comment Procedures Section of the preamble for additional 
information on how to file paper comments.

[[Page 60106]]

FOR FURTHER INFORMATION CONTACT: 
Peter Radway (Technical Information), Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, Phone: 202-
502-8782, e-mail: peter.radway@ferc.gov.
Julia A. Lake (Legal Information), Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, Phone: 202-
502-8370, e-mail: julia.lake@ferc.gov.

SUPPLEMENTARY INFORMATION:

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. 
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

    1. The Bonneville Power Administration (Bonneville) has submitted 
for the Federal Energy Regulatory Commission (Commission)'s approval a 
new methodology for determining the average system cost (ASC) of a 
utility's resources under section 5(c) of the Pacific Northwest 
Electric Power Planning and Conservation Act (Northwest Power Act).\1\ 
Bonneville requested that the Commission revise its regulations to 
incorporate the new methodology and to make the revised regulations 
effective October 1, 2008. On an interim basis, the Commission is 
conditionally revising its regulations governing the ASC methodology 
used by Bonneville in its Residential Exchange Program. The Commission 
also is requesting comments on whether, on a final basis, the 
Commission should approve the new ASC methodology proposed by 
Bonneville.
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    \1\ 16 U.S.C. 839(c).
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Background

    2. Section 5(c) of the Northwest Power Act provides for a 
Residential Exchange Program, which broadly speaking is designed to 
make the benefit of Bonneville's relatively low preference power rates 
available to residential customers of investor-owned utilities in the 
Pacific Northwest.\2\ Although the Residential Exchange Program is 
available to any Pacific Northwest utility, the primary beneficiaries 
of the exchange are investor-owned utilities. Under the Residential 
Exchange Program, a utility may sell power to Bonneville at the average 
system cost of that utility's resources.\3\ Bonneville then sells the 
same amount of power back to the utility at Bonneville's priority firm 
exchange rate.\4\ The power exchange is generally viewed as a paper 
transaction.\5\ In almost all instances, Bonneville makes a payment to 
the utility for the difference between the utility's average system 
cost and Bonneville's priority firm exchange rate, multiplied by the 
utility's residential and small farm load.
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    \2\ Id.
    \3\ 16 U.S.C. 839c(c)(1).
    \4\ Id. This rate is generally a lower rate.
    \5\ See CP Nat'l Corp. v. BPA, 928 F.2d 905, 907 (9th Cir. 1991) 
(quoting Public Utility Commissioner of Oregon v. BPA, 583 F. Supp. 
752, 754 (D. Or. 1984)).
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    3. The Northwest Power Act does not define what constitutes the 
average system cost of a utility's resources.\6\ Instead, the Act 
grants Bonneville's Administrator the authority to establish a 
methodology for determining an exchanging utility's average system cost 
through a stakeholder process in consultation with the Northwest Power 
Planning Council, Bonneville's customers, and appropriate State 
regulatory bodies in the region.\7\ The Northwest Power Act directed 
the Administrator to exclude the following three types of costs from 
the average system cost: (1) The cost of additional resources in an 
amount sufficient to serve any new large single load of the utility; 
(2) the cost of additional resources in an amount sufficient to meet 
any additional load outside the region occurring after December 5, 
1980; and (3) any costs of any generating facility which is terminated 
prior to initial operation.\8\ Outside these explicit exclusions, the 
Northwest Power Act is silent on the costs that may be included or 
excluded in the average system cost. Bonneville's Administrator decides 
what costs should be considered when calculating the average system 
cost, and what process should be used to make that determination.
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    \6\ 16 U.S.C. 839c(c)(2).
    \7\ 16 U.S.C. 839c(c)(7).
    \8\ 16 U.S.C. 839c(c)(7)(A)-(C).
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    4. The Commission's role in this exchange program is two-fold. 
First, under section 5(c)(7) of the Act, while Bonneville develops a 
methodology for determining a utility's ASC (after consulting with 
various affected groups), the Commission must ``review and approve'' 
the methodology. Neither the statute nor its legislative history 
explains the nature of this review, however.\9\
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    \9\ Methodology for Sales of Electric Power to Bonneville Power 
Administration, Order No. 400, FERC Stats. & Regs. ] 30,601 at 
31,161 (1984), reh'g denied, Order No. 400-A, FERC 30 FERC ] 61,108 
(1985).
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    5. The Commission's second role in the exchange program arises from 
its Federal Power Act (FPA) \10\ responsibility to review the wholesale 
sales rates of individual investor-owned utilities; the Commission 
reviews the rates for such sales from the investor-owned utilities to 
Bonneville based on the ASC methodology. The Commission's existing 
rules (18 CFR 35.30 and 35.31) provide that the Commission will approve 
under the FPA any sale to Bonneville that is based on correct 
application of an approved methodology.\11\
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    \10\ 16 U.S.C. 824, 824d, 824e.
    \11\ Order No. 400, FERC Stats. & Regs. ] 30,601 at 31,161.
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    6. On July 14, 2008, Bonneville filed a revised ASC methodology to 
replace the current ASC methodology approved by the Commission on a 
final basis in 1984, and codified in part 301 of the Commission's 
regulations (July 2008 Filing).\12\ In its July 2008 Filing (which was 
corrected on September 12, 2008),\13\ Bonneville states that this is 
the first revision to its ASC methodology in 24 years, and reflects 
changes in the energy industry that have transpired during that time.
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    \12\ 18 CFR Part 301.
    \13\ The July 2008 Filing was noticed in Docket No. EF08-2011-
000 in the Federal Register, 72 FR 32633 (2008), with protests and 
interventions due on or before August 13, 2008. Timely motions to 
intervene and comments were filed by Avista Corporation, PacifiCorp, 
Portland General Electric Company, Puget Sound Energy, Inc., Public 
Utility District No. 1 of Clark County, Washington, and the Public 
Utility District No. 1 of Grays Harbor County, Washington. The 
Public Power Council and the Public Utility District No. 1 of 
Snohomish County, Washington filed motions to intervene out of time. 
In addition, the Idaho Power Company filed comments and a partial 
protest. The Idaho Public Utilities Commission filed a notice of 
intervention and protest. Bonneville filed an answer to interested 
parties' comments and protests. Additionally, Bonneville filed an 
errata correction to its initial filing on September 12, 2008.
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    7. Bonneville explains that the stakeholder process that resulted 
in this revised ASC methodology began in May of 2007, following two 
Ninth Circuit opinions that held that Bonneville exceeded its statutory 
authority when it entered into certain Residential Exchange Program 
Settlement Agreements, and remanded Bonneville's WP-02 wholesale power 
rates for improperly allocating the costs of the Residential Exchange 
Program Settlement Agreements to its preference customers.\14\ 
Bonneville explains that it ceased making Residential Exchange Program 
payments following these 2007 decisions.
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    \14\ See Portland General Elec. Co. v. BPA, 501 F.3d 1009 (9th 
Cir. 2007); Golden NW Aluminum, Inc. v. Bonneville Power Admin., 501 
F.3d 1037 (9th Cir. 2007).
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    8. Bonneville states that, before it can provide Residential 
Exchange Program payments, it must re-establish the Residential 
Exchange Program. According to Bonneville, this requires the following: 
(1) Negotiation of Residential Purchase and Sale

[[Page 60107]]

Agreements; (2) establishment of a Priority Firm Exchange rate in a 
Northwest Power Act section 7(i) \15\ rate adjustment proceeding; and 
(3) calculation of utilities' respective average system costs under an 
ASC methodology. Bonneville notes that, in a separate Bonneville 
proceeding, it negotiated new Residential Purchase and Sale Agreements 
to be effective October 1, 2008. And, in another Bonneville proceeding, 
it developed a revised priority firm exchange rate that it will submit 
to the Commission in a separate docket for interim approval. Bonneville 
explains that it must ensure that an ASC methodology is in effect to 
determine exchanging utilities' average system costs to implement the 
Residential Exchange Program on October 1, 2008. Bonneville, therefore, 
requests the Commission to grant interim approval of the revised ASC 
methodology no later than October 1, 2008.
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    \15\ 16 U.S.C. 839e.
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    9. In its July 2008 Filing, Bonneville explains that the revised 
ASC methodology retains characteristics of the current ASC methodology. 
Bonneville explains, further, that the key differences are in how 
average system costs are calculated as well as the substance of the 
costs included and excluded from the average system cost calculation. 
Bonneville states that the revised ASC methodology adopts a streamlined 
approach to the average system cost calculations by using a different 
source of average system cost data, i.e., FERC Form No. 1 data, instead 
of state retail rate orders. Bonneville notes that, in addition, it 
proposes to adjust the average system costs less frequently. Bonneville 
asserts that the revised ASC methodology allows each utility to file a 
single, combined average system cost for its entire within-region 
service territory as opposed to an average system cost for each state 
jurisdiction in which it operates.
    10. Bonneville also explains that it is proposing to establish a 
two-year average system cost that will correspond with its two-year 
wholesale power rate periods. Bonneville explains, further, that 
utilities' average system costs will stay fixed except for pre-
determined adjustments to reflect the costs of new resources incurred 
during the rate/exchange period. According to Bonneville, these 
features will lessen the number of average system costs filings 
reviewed by Bonneville and the Commission.
    11. Bonneville explains that the revised ASC methodology also 
changes the average system cost treatment of certain costs. Bonneville 
states that it is allowing utilities to exchange a full return on 
equity (instead of the weighted cost of debt); the utility's marginal 
Federal income tax; and the utility's transmission plant costs.
    12. Bonneville requests Commission approval of this new ASC 
methodology.

Discussion

    13. For the reasons discussed below, the Commission has determined 
to conditionally grant interim approval of Bonneville's new ASC 
methodology. We note, however, that the methodology must be further 
reviewed before final approval can be given; this review cannot be 
completed during the short time period in which the methodology has 
been before the Commission.
    14. Interim approval is necessary to further the intent of the 
Northwest Power Act. An approved (by the Commission) ASC methodology is 
fundamental to the Residential Exchange Program found in section 5 of 
the Northwest Power Act. The methodology defines the rates at which 
sales will be made to Bonneville which, when made, will permit 
exchanges to occur.
    15. This warrants approval on an interim basis of Bonneville's 
revised ASC methodology. However, the Commission is obligated to review 
and approve the methodology in accordance with certain procedures and 
its responsibilities to protect the public interest, and the Commission 
has yet to finish its review of the proposed methodology. For these 
reasons, the approval granted here is interim only.
    16. Moreover, such interim approval must be conditioned to ensure 
that the public interest is protected during the time period the 
interim approval is in place. The revised ASC methodology will affect 
rates paid by, and to, Bonneville. To the extent that the ASC 
methodology finally approved by the Commission differs from that filed 
by Bonneville in its July 2008 filing, and which is approved on an 
interim basis here, the rates paid may be different from the rate under 
the ASC methodology finally approved by the Commission. The Commission 
must be assured that any such difference can be corrected, through 
refund or surcharge, to the extent of the difference, should that be 
appropriate. To ensure this result, the Commission grants interim 
approval only conditionally and subject to refund or surcharge.\16\
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    \16\ Order No. 400, FERC Stats. & Regs. ] 30,601 at 31,162.
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    17. The Commission attaches this condition with the full awareness 
that, by so doing, some uncertainty is injected into the exchange 
process. Rates paid may be too high or too low, depending upon the ASC 
methodology finally approved by the Commission. However, under the 
circumstances, some uncertainty is unavoidable. The Commission staff 
has completed a preliminary review of the methodology, however, and is 
satisfied that such uncertainty is minimal. Moreover the methodology is 
a product not only of a stakeholder process, which should serve to 
minimize any uncertainty, but also of notice and comment procedures. 
This provides good grounds for finding that, for purposes of interim 
approval, due process has been observed.\17\
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    \17\ Id.
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Paperwork Reduction Act Statement

    18. A Paperwork Reduction Act Statement is not required for this 
interim rule because the regulations adopt a methodology used by a 
federal power marketing administration, in this case Bonneville.

Environmental Analysis

    19. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\18\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in these exclusions are Commission actions 
addressing proposed public utility rates and Commission confirmation, 
approval, and disapproval of rate filings submitted by federal power 
marketing administrations under the Northwest Power Act.\19\ The 
actions herein fall within this categorical exclusion in the 
Commission's regulations.
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    \18\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \19\ 18 CFR 380.4(a)(15).
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Regulatory Flexibility Act

    20. The Regulatory Flexibility Act of 1980 (RFA) \20\ generally 
requires a description and analysis of the effect that an interim rule 
will have on small entities or a certification that the rule will not 
have a significant economic impact on a substantial number of small 
entities.
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    \20\ 5 U.S.C. 601-12.
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    21. The Commission concludes that this interim rule will not have 
such an impact on a substantial number of small entities. Bonneville is 
a federal power marketing administration. And the investor-owned 
utilities which are

[[Page 60108]]

participating in the Residential Exchange Program are not small 
entities.\21\ Moreover, the number of utilities participating in the 
program is not substantial; only nine utilities whose rates are within 
the Commission's jurisdiction are participating in the program.
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    \21\ 5 U.S.C. 602(3) citing section 3 of the Small Business Act, 
15 U.S.C. 632. Section 3 of the Small Business Act defines ``small 
business concern'' as a business which is independently owned and 
operated, and which is not dominant in its field of operation.
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    22. For these reasons, the Commission certifies under the RFA that 
this interim rule will not have a significant economic effect on a 
substantial number of small entities.

Comment Procedures

    23. The Commission invites interested persons to submit comments on 
the matters and issues raised by the proposed revised ASC methodology. 
Comments are due November 10, 2008.\22\ Comments must refer to Docket 
Nos. EF08-2011-000 and RM08-20-000, and must include the commenter's 
name, the organization they represent, if applicable, and their address 
in their comments.
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    \22\ All motions to intervene, comments, protests, and all 
notices of intervention filed in Docket No. EF08-2011-000; will be 
considered to have been filed in Docket No. RM08-20-000. All 
comments and protests filed in Docket No. EF08-2011-000 will be 
addressed in the final rule issued in Docket No. RM08-20-000. 
Inventernors in Docket No. EF08-2011-000 wising to file additional 
commments may do so.
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    24. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://
www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    25. Commenters that are not able to file comments electronically 
must send an original and 14 copies of their comments to the Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street, NE., Washington, DC 40246.
    26. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

Document Availability

    27. In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's home page http://www.ferc.gov and in 
the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington, DC 20426.
    28. From the Commission's home page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the document number excluding the last three digits of this document in 
the docket number field.
    29. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from FERC Online Support at (202) 
502-6652 (toll free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

Effective Date

    30. For the reasons discussed above, the Commission finds good 
cause under section 553(d)(3) of the Administrative Procedure Act \23\ 
to make this rule effective immediately, rather than 30 days after 
publication in the Federal Register. The long-term impact of delaying 
early implementation of a new revised ASC methodology justifies its 
immediate effectiveness. This interim rule, therefore, will take effect 
on October 1, 2008.
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    \23\ 5 U.S.C. 553(d)93.
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List of Subjects in 18 CFR Part 301

    Electric power rates; Electric utilities; Reporting and 
recordkeeping requirements.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

0
In consideration of the foregoing, the Commission amends Title 18, 
Chapter I of the Code of Federal Regulations, by revising Part 301 to 
read as follows:

PART 301--AVERAGE SYSTEM COST METHODOLOGY FOR SALES FROM UTILITIES 
TO BONNEVILLE POWER ADMINISTRATION UNDER NORTHWEST POWER ACT

Sec.
301.1 Applicability.
301.2 Definitions.
301.3 Filing procedures.
301.4 Bonneville Power Administration's Average System Cost review 
process.
301.5 Exchange Period Average System Cost determination.
301.6 Change in Average System Cost methodology.
301.7 Sample time line review procedures.
301.8 Appendix 1 instructions.
301.9 Functionalization of Average System Cost methodology.
Table 1 to Part 301--Functionalization and Escalation Codes.
Appendix 1 to Part 301--Bonneville Power Administration Residential 
Purchase and Sales Agreement
Appendix 2 to Part 301--Chief Financial Officer Attestation

    Authority: 16 U.S.C. 839-839h.

Sec.  301.1  Applicability.

    The regulations in this part provide the procedures by which 
regional utilities will submit Average System Cost (ASC) filings to the 
Bonneville Power Administration (Bonneville), and by which Bonneville 
will review those filings. Bonneville's review will determine a 
utility's ASC for the purpose of participating in the Residential 
Exchange Program under section 5(c) of the Pacific Northwest Electric 
Power Planning and Conservation Act (Northwest Power Act). 16 U.S.C. 
839c(c).

Sec.  301.2  Definitions.

    For purposes of this section, the following definitions apply:
    Appendix 1. Appendix 1 is the electronic form on which a utility 
reports its Contract System Costs and other necessary data to 
Bonneville for the calculation of the utility's Base Period.
    Average System Cost (ASC). The rate charged by a utility to 
Bonneville for the agency's purchase of power from the utility under 
section 5(c) of the Northwest Power Act for each Exchange Period, and 
is the quotient obtained by dividing the Contract System Costs by 
Contract System Load.
    Base Period. The calendar year of the most recent Form 1 data.
    Base Period ASC. The ASC determined in the Review Period using the 
utility's Base Period data.
    Contract High Water Mark (CHWM). The average MW amount used to 
define access to Tier 1-priced power. CHWM is equal to the adjusted 
historical load for each customer proportionately scaled to Tier 1 
System Resources and adjusted for conservation achieved. The CHWM is 
specified in each eligible customer's Contract High Water Mark 
Contract.

[[Page 60109]]

    Commission. The Federal Energy Regulatory Commission.
    Contract System Costs. The utility's costs for production and 
transmission resources, including power purchases and conservation 
measures, which costs are includable in, and subject to, the provisions 
of Appendix 1. Under no circumstances will Contract System Costs 
include costs excluded from ASC by section 5(c)(7) of the Northwest 
Power Act.
    Contract System Load. The total regional retail load included in 
Form 1, or for a consumer-owned utility (preference customers), the 
total retail load from the most recent annual audited financial 
statement as adjusted pursuant to the ASC methodology.
    Exchange Period. The period during which a utility's Bonneville-
approved ASC is effective for the calculation of the utility's 
Residential Exchange Program benefits. The initial Exchange Period 
under this ASC methodology is from October 1, 2007, through September 
30, 2009. Subsequent Exchange Periods will be the period of time 
concurrent with the Bonneville rate period beginning October 1, or the 
effective date of Bonneville's rate period.
    Exchange Period ASC. The Base Period ASC escalated to a year(s) 
consistent with the Exchange Period.
    Form 1. The annual filing submitted to the Federal Energy 
Regulatory Commission required by 18 CFR Sec.  141.1.
    Jurisdiction. The service territory of the utility within which a 
particular regulatory body has authority to approve a utility's retail 
rates. Jurisdictions must be within the Pacific Northwest region as 
defined in the Northwest Power Act.
    Labor Ratios. The ratios which assign costs on a pro rata basis 
using salary and wage data for Production, Transmission, and 
Distribution/Other functions included in the utility's most recently 
filed Form 1. For consumer-owned utilities, comparable data will be 
used based on the cost-of-service study used as the basis for retail 
rates at the time of review.
    New Large Single Load. That load defined in section 3(13) of the 
Northwest Power Act, and determined by Bonneville as specified in power 
sales contracts and Residential Sale and Purchase Agreements (RPSA) 
with its Regional Power Sales Customers.
    Public Purpose Charge. Any charge based on a utility's total retail 
sales in a jurisdiction that is given to independent nonprofit entities 
or agencies of state and local governments for the purpose of funding 
within the utility's service territory including:
    (1) Conservation programs in lieu of utility conservation programs; 
and
    (2) Acquisition of renewable resources.
    Rate Period High Water Mark (RHWM). The amount used to define each 
customer's eligibility to purchase power at a Tier 1 price for the 
relevant Rate Period, subject to the customer's New Requirement, 
expressed in average megawatts (aMW). RHWM is equal to the customer's 
CHWM as adjusted for changes in Tier 1 System Resources. The RHWM is 
determined for each eligible customer in the RHWM Process preceding 
each rate case.
    Regional Power Sales Customer. Any entity that can contract 
directly with Bonneville for the purchase of power under sections 5(b), 
5(c), or 5(d) of the Northwest Power Act for delivery in the region as 
defined by section 3(14) of the Northwest Power Act.
    Regulatory Body. A state Commission or consumer-owned utility 
governing body, or other entity authorized to establish retail electric 
rates in a Jurisdiction.
    Residential Purchase and Sale Agreement (RPSA). The power sales 
contract under section 5(c) of the Northwest Power Act between 
Bonneville and the utility that defines and implements the power 
purchase and sale.
    Review Period. The period of time during which a utility's Appendix 
1 is under review by Bonneville. The Review Period begins on June 1, 
and ends on or about November 15 of the fiscal year prior to the fiscal 
year Bonneville implements a change in wholesale power rates.
    Utility. An investor-owned or consumer-owned (preference) Regional 
Power Sales Customer that has executed a Residential Purchase and Sale 
Agreement.

Sec.  301.3  Filing procedures.

    The following procedures provide the filing requirements for all 
utilities that file an Appendix 1 to participate in the Residential 
Exchange Program. Utilities must file an Appendix 1 with Bonneville to 
permit the calculation of each utility's ASC.
    (a) Initial Exchange Period (2009).
    (1) A utility's ASC for fiscal year FY 2009 will be determined by 
Bonneville in accordance with this ASC methodology, and will constitute 
the effective ASC for the Residential Exchange Program effective 
October 1, 2008, unless:
    (i) The Commission fails to approve the methodology;
    (ii) The Commission amends the methodology in a manner that changes 
the utility's ASC established by Bonneville; or
    (iii) The methodology is legally challenged, and not affirmed on 
appeal by the United States Court of Appeals for the Ninth Circuit.
    (iv) The Base Period Appendix 1 filing will be from CY 2006. The 
Initial Exchange Period will begin October 1, 2008 provided that the 
Commission grants the methodology interim or final approval by that 
date. The Initial Exchange Period will end on September 30, 2009.
    (2) Since the Initial Exchange Period begins on October 1, 2008, 
and the utility filings for FY 2008 are due that same day, Bonneville 
will pay the exchanging utilities based on their October 1, 2008 filed 
ASC, and calculate a true-up to the final ASC after the Bonneville 
Review Period is concluded, and Bonneville issues the final ASC 
reports. If a utility fails to file an Appendix 1 by October 1, 2008, 
Bonneville will follow the procedures outlined in paragraphs (d) and 
(e) of this section. Prior to the commencement of the Bonneville review 
process, Bonneville will publish a schedule for the review of the 
filings. Bonneville may issue a schedule different from the prescribed 
schedule in order to ensure that ASCs are established in time to be 
trued-up during FY 2009.
    (b) Second Exchange Period (FY 2010-2011).
    (1) For the Second Exchange Period, utilities are required to 
submit their ASC filings by October 1, 2008 for FY 2010-2011. If a 
utility fails to file an Appendix 1 by October 1, 2008, Bonneville will 
follow the procedures outlined in paragraphs (d) and (e) of this 
section. Prior to the commencement of the Bonneville Review Period, 
Bonneville will publish a schedule for review of the filings. 
Bonneville may issue a schedule different from the prescribed schedule 
in order to ensure that ASCs are established in time to be incorporated 
in Bonneville's FY 2010-2011 wholesale power rate case.
    (2) After Bonneville's review process is concluded, Bonneville will 
issue utility ASC Reports to reflect the final ASCs for the FY 2010-
2011 rate period.
    (c) Subsequent Exchange Periods.
    (1) Subsequent Exchange Periods will be equal to the term of 
subsequent Bonneville wholesale power rate periods. ASCs will change 
during the Exchange Periods only for the reasons provided in paragraph 
(a)(1) of this section.
    (2) Except as provided for in the Initial and Second Exchange 
Periods, utilities must file electronically at least one Appendix 1 
with Bonneville by

[[Page 60110]]

June 1 of each year. In years when Bonneville is not conducting a 
review process, these filings will be for informational purposes only, 
and will not change a utility's ASC. The Appendix 1 must be accompanied 
by supporting documentation, studies and analyses used to prepare the 
Appendix 1.
    (i) For investor-owned utilities, Appendix 1 must be based on the 
utility's most recently filed Form 1 and limited information from prior 
Form 1 filings as required.
    (ii) For consumer-owned utilities, Appendix 1 must be based on the 
utility's most recent audited financial information, and must be 
accompanied by a cost-of-service analysis.
    (iii) Each Appendix 1 must contain an attestation signed by a 
senior officer of the utility stating that the filing has been compiled 
in accordance with the Commission's Uniform System of Accounts, the ASC 
methodology in part 301 of the Commission's regulations, and Generally 
Accepted Accounting Principles, and is consistent with applicable 
orders and policies of the utility's Regulatory Body.
    (d) Failure to file an Appendix 1. If a utility fails to timely 
file an Appendix 1, and refuses to cure the problem within the period 
to cure provided in paragraph (f) of this section, Bonneville will make 
the utility's Appendix 1 filing. The utility will waive its right to 
participate in the ASC review proceeding to establish its ASC. All 
other parties will be permitted to participate, and present arguments 
challenging the utility's ASC.
    (e) Filing a patently deficient Appendix 1. If a utility files its 
initial Appendix 1, and it is patently deficient as determined by 
Bonneville, and the period to cure, as outlined in paragraph (f) of 
this section, has expired, Bonneville will make the utility's Appendix 
1 filing. The utility will waive its right to participate in the ASC 
review proceeding to establish its ASC. A utility filing a patently 
deficient ASC filing must allow Bonneville the discretion to set its 
ASC for the Exchange Period, and Bonneville will not be required to 
include any proposed adjustments for resource changes or changes in 
service territories in the Appendix 1 filing.
    (f) Period to cure. If a utility fails to timely file an Appendix 
1, or if it files an ASC that Bonneville determines is patently 
deficient, Bonneville will provide the utility with written notice and 
a period of seven (7) calendar days within which to file or to re-file 
a new or corrected Appendix 1. In the event the utility fails to file 
or re-file by the end of the seven-day cure period, or if the re-filed 
Appendix 1 is determined patently deficient, Bonneville will make the 
utility's Appendix 1 filing. The utility will waive its right to 
participate in the ASC review proceeding to establish its ASC. All 
other parties will be permitted to participate and present arguments 
challenging the utility's ASC. A utility filing a patently deficient 
ASC filing will allow Bonneville discretion to set its ASC for the 
Exchange Period, and Bonneville will not be required to include any 
proposed adjustments for resources changes or changes in service 
territories in the Appendix 1 filing.
    (g) Failure to file an Appendix 1 because of a new Residential 
Purchase and Sale Agreement. After the Initial and Second Exchange 
Periods, if a utility fails to file its Appendix 1 by June 1 because it 
executed a Residential Purchase and Sale Agreement after commencement 
of a Review Period or during the subsequent Exchange Period, Bonneville 
may set the utility's ASC equal to the Priority Firm Exchange rate 
until the end of the Exchange Period.
    (h) Notice of filing of Appendix 1. (1) After a utility files an 
Appendix 1 electronically, Bonneville will post the filings and non-
confidential documentation on its electronic Web site. Access to the 
information will be subject to any confidentiality rules or 
requirements established by Bonneville.
    (2) Bonneville will advise parties of the right to file a petition 
to intervene in Bonneville's ASC review process.

Sec.  301.4  Bonneville Power Administration's Average System Cost 
Review Process.

    During a Review Period, the following procedures apply. These 
procedures will not apply to informational ASC filings made outside of 
a Review Period.
    (a) Bonneville may petition to intervene in each retail rate 
proceeding for each utility participating in the Residential Exchange 
Program. If Bonneville or any of its Regional Power Sales Customers is 
denied the right to intervene in a retail rate review proceeding of a 
filing utility when the intervention is for purposes of obtaining any 
information regarding costs or facts relevant to the determination of a 
utility's ASC (after making a good faith effort to intervene in the 
retail rate proceeding and timely complying with applicable procedures 
to intervene in the retail rate proceeding), Bonneville may set that 
utility's ASC equal to the Priority Firm Exchange Rate for the 
following Exchange Period. Exchanging utilities must provide Bonneville 
and Regional Power Sales Customers with at least 60 days notice of 
their intent to change their retail rates.
    (b) Each Appendix 1 will be reviewed by Bonneville or its designee 
and subject to a public process to determine whether the Contract 
System Costs are consistent with Generally Accepted Accounting 
Principles for electric utilities, whether Contract System Costs 
contain only allowed costs, and whether the revised Appendix 1 complies 
with the requirements of the ASC methodology, including applicable 
definitions and requirements incorporated from the Commission's Uniform 
System of Accounts. In addition, each Appendix 1 will be reviewed by 
Bonneville or its designee to determine whether the Contract System 
Load used by the utility is an appropriate load for purposes of the 
utility's ASC computation.
    (c)(1) In calculating ASCs, Bonneville will make an independent 
determination of the following:
    (i) The appropriateness of the inclusion of costs;
    (ii) The reasonableness of the costs included in Contract System 
Costs; and
    (iii) The appropriateness of Contract System Loads.
    (2) Bonneville will not be obligated to pay an ASC different than 
the ASC based on Contract System Costs and Contract System Load as 
determined by Bonneville.
    (3) If a final order of the Commission or a reviewing court rejects 
Bonneville's ASC determination, the ASC payable by Bonneville will be 
the ASC as revised by Bonneville on remand.
    (d) The Appendix 1 filing will be subject to review as follows:
    (1) The Bonneville review process (not including the Initial and 
Second Exchange Periods) commences June 1 (Day 1) of the Review Period 
(or other date as may be established by Bonneville). Bonneville will 
review all utilities' ASCs concurrently in a public process.
    (2) The dates identified in these regulations and those listed on 
the sample time line shown in Sec.  301.7 are generic, and intended to 
illustrate a time line that is representative of the ASC review 
process. Unless specified, the days represent calendar days. Each 
spring, prior to the Review Period, Bonneville will post on its ASC 
methodology Web site (http://www.bpa.gov/corporte/finance/ascm) or its 
successor, a detailed schedule, accommodating the applicable holidays 
and weekends, that will be the official schedule for that Review 
Period.
    (e) Review Period time line.
    (1) Day 1. Utility filings due to Bonneville.
    (2) Day 3. Bonneville posts the utility filings to its electronic 
Web site.

[[Page 60111]]

    Access to the information will be subject to any confidentiality 
rules or requirements established by Bonneville.
    (3) Day 7. Deadline to file utility-specific petitions to intervene 
with Bonneville for the review process. Any Regional Power Sales 
Customer or state utility Regulatory Body who so requests will be 
accorded party status for Bonneville's ASC review process if the 
request is received by the established deadline. Other interested 
parties also may submit a petition to intervene, and Bonneville will 
grant party status at its discretion. Petitions to intervene must state 
with particularity the petitioner's interest in the ASC review 
proceeding. Petitions to intervene must be filed for each respective 
Bonneville review proceeding in order for a party to comment on the 
individual proceedings. The filing utility is automatically a party to 
its own ASC review proceeding. Bonneville will grant or deny petitions 
to intervene within seven (7) days after the deadline for filing the 
petitions.
    (4) Day 10. Bonneville grants or denies petitions to intervene.
    (5) Day 11-66. Parties allowed to submit data requests. Bonneville 
and parties will file data requests electronically with the utility and 
Bonneville. Bonneville will make data requests available to all 
parties. Each utility will respond to requests for information relevant 
to the utility's Appendix 1 filing, provided that the furnishing of 
proprietary or confidential information to any party may be made 
contingent on the granting of proper safeguards to prevent unauthorized 
use or disclosure. The responses must be sent to the requester and 
Bonneville. For each data request, the responding utility has seven (7) 
days to provide the requested data or object. If a utility files an 
objection to a data request, the party submitting the data request has 
four (4) days to respond to the objection. After the response to the 
objection is received, or the four (4) days to respond has elapsed, 
Bonneville then has seven (7) days to issue a ruling as to whether the 
utility's objection will be sustained or overruled. If the objection is 
overruled, the utility must provide the data requested within seven (7) 
days after the ruling. If a utility does not provide the requested 
data, Bonneville may, in its discretion, remove from Contract System 
Costs all costs associated with the data not provided.
    (6) Day TBD. Bonneville will begin workshops on all Appendix 1 
filings based on the specific schedules. Utilities filing an Appendix 1 
will have staff or agents available for questioning by Bonneville and 
other parties to the proceeding. The primary purpose of the first 
workshop is to clarify data, work papers, supporting documentation and 
assumptions used to prepare the Appendix 1.
    (7) Day 88. By this day, Bonneville and parties may file 
electronically with Bonneville an issue list identifying contested 
elements of a utility's ASC filing and the basis for the parties' 
issues. Bonneville will make the issue lists available to all parties.
    (8) Day 102. By this day, each filing utility will electronically 
file a response to the issue lists. Bonneville and other parties also 
may file comments in response to the issue lists.
    (9) Day 108. By this day, a workshop will be held to discuss and 
resolve the issues raised by parties through their issue lists.
    (10) Day 111. Requests for oral argument before the Administrator 
or his/her designee must be submitted in writing to Bonneville by this 
day. The requests must contain a statement providing reasons why the 
party believes oral argument is necessary.
    (11) Day 114. By this day, Bonneville, at its discretion, may grant 
or deny any request for oral argument.
    (12) Day 123. In the event a request for oral argument is granted, 
the requesting party will present its arguments first. Responding 
parties will present their arguments following the requesting party's 
arguments. The Administrator or his/her designee, at his discretion, 
may provide an opportunity for the requesting party to reply. Oral 
arguments will be presented no later than this day.
    (13) Day 141. By this day, Bonneville will publish for comment, and 
serve electronically draft utility ASC reports on all parties. The 
reports will contain analyses and decisions on all contested issues 
raised in the ASC review process.
    (14) Day 154. By this day, the utility and parties may file 
comments on the draft utility ASC reports.
    (15) Day 167. The Bonneville Administrator will issue final utility 
ASC reports.
    (16) If Bonneville has not issued the final utility ASC reports by 
the end of the Review Period, the ASC filed by the utility will be the 
Exchange Period ASC until the date Bonneville issues the final utility 
ASC reports. The final ASCs determined by Bonneville will then be the 
Exchange Period ASCs effective back to the beginning of the Exchange 
Period and until the end of the Exchange Period.

Sec.  301.5  Exchange Period Average System Cost Determination.

    (a) Escalation to Exchange Period.
    (1) Bonneville will escalate Bonneville-approved Base Period costs 
to the midpoint of the fiscal year for a one-year rate period/Exchange 
Period, and to the midpoint of the two-year period for a two-year rate 
period/Exchange Period to calculate Exchange Period ASCs.
    (2) For purposes of the escalation referenced in paragraph (a)(1) 
of this section, Bonneville will use Global Insight's (or its 
successor) forecast of cost increases for capital costs and fuel 
(except natural gas), Operations & Maintenance and General & 
Administrative expenses; and Bonneville's forecast of market prices for 
investor-owned utility purchases to meet load growth and to estimate 
short-term and non-firm power purchase costs and sales revenues; and 
Bonneville's forecast of natural gas prices and Bonneville's estimates 
of the rates it will charge for its Priority Firm and other products.
    (3) With the exception of the natural gas escalator provided by 
Bonneville, the following list of acronyms defines Global Insight's 
escalation codes. These escalators will be used for each line item 
included in Appendix 1.

(i) A&G--Administrative and General.
(ii) CACNT--Customer Account.
(iii) CD--Construction, Distribution Plant.
(iv) CONSTANT--Constant.
(v) CSALES--Customer Sales.
(vi) CSERVE--Customer Service.
(vii) COAL--Coal.
(viii) DMN--Distribution Maintenance.
(ix) HMN--Hydro Maintenance.
(x) HOPS--Hydro Operations.
(xi) INF--Inflation.
(xii) NATGAS--Natural Gas.
(xiii) NFUEL--Nuclear Fuel.
(xiv) NMN--Nuclear Maintenance.
(xv) NOPS--Nuclear Operations.
(xvi) OMN--Other Production Maintenance.
(xvii) OOPS--Other Production Operations.
(xviii) SMN--Steam Maintenance.
(xix) SOPS--Steam Operations.
(xx) TMN--Transmission Maintenance.
(xxi) TOPS--Transmission Operations.
(xxii) WAGES--Wages.

    (4) If any of the escalators specified in the ASC methodology are 
no longer available, Bonneville will designate a replacement source of 
escalators that, as near as possible, replicates the results produced 
by the prior escalator, and, if a replacement source is not available, 
the replacement escalator will be the forecast of the GDP Price 
Deflator.
    (5) Bonneville will base the costs of power products purchased from 
Bonneville on Bonneville's forecast of prices for its products.
    (b) Treatment of sales for resale and power purchases.

[[Page 60112]]

    (1) Bonneville will escalate long-term and intermediate term (as 
defined by the Commission) firm purchased power costs and sales for 
resale revenues at the rate of inflation.
    (2) Bonneville will not normalize short-term purchases and sales 
for resale. The short-term purchases and sales for resale for the Base 
Period will be used as the starting values. A utility will be allowed 
to include new plant additions, and use a utility-specific forecast for 
the price of purchased power and sales for resale price to value 
purchased power expenses and sales for resale revenue to be included in 
the Exchange Period ASC.
    (3) Bonneville will use the following method to determine separate 
market prices to forecast short-term purchased power expense and sales 
for resale revenues to calculate Exchange Period ASCs:
    (i) The utility's average short-term purchased power price and 
short-term sales for resale price will be calculated for each year for 
the most recent three years of actual data (Base Period and prior two 
years).
    (ii) The midpoint between the utility's average short-term sales 
for resale price will be calculated for each of the years in paragraph 
(b)(3)(i) of this section.
    (iii) The percentage spread around the utility's midpoint between 
the average short-term purchased power price and short-term sales for 
resale price will be escalated for each of the years identified in 
paragraph (b)(3)(i) of this section.
    (iv) A weighted average spread for the utility's most recent three 
years of actual data (Base Period and prior two years) will be 
calculated. The following weighting scale will be used:
    (A) Three (3) times Base Period spread.
    (B) Two times (Base Period minus 1) spread.
    (C) One time (Base Period minus 2) spread.
    (v) The Base Period midpoint price calculated in paragraph 
(b)(3)(ii) of this section will be applied to the forecasted midpoint 
calculated in paragraph (b)(3)(iv) of this section to determine the 
purchased power and sales for resale price, to value purchased power 
expenses and sales for revenue to be included in the Exchange Period 
ASC.
    (vi) The weighted average spread calculated in paragraph (b)(3)(iv) 
of this section to determine the purchased power and sales for resale 
price, to value purchased power expenses and sales for resale revenue 
to be included in the Exchange Period ASC.
    (vii) This same method will be used to calculate the market price 
forecast for short-term, purchased power expense and sales for resale 
revenues for use in the load growth not met by new resource additions.
    (c) Major resource additions and materiality thresholds.
    (1) During the Exchange Period, Bonneville will allow changes to a 
utility's ASC to account for major new purchased power contracts or 
major new resource additions that come on-line, and are used to meet 
the utility's retail load. These changes, however, have to meet a 
materiality threshold in order for Bonneville to allow an ASC to 
change. These ASCs will be determined by Bonneville during the Review 
Period. The changes to the ASC will become effective when the resource 
begins commercial operation, or power is received under the purchased 
power contract. The criteria also will apply to resources that are 
sold, transferred, or retired.
    (2) Bonneville will use the following method to determine the 
changes in ASC due to major new resource additions or reductions, 
subject to meeting the materiality threshold. These additions will 
include new production resource investments, new generating resource 
investments, new transmission investments, long-term generating 
contracts, pollution control and environmental compliance investments 
relating to generating resources, transmission resources or contracts, 
hydro relicensing costs and fees, and plant rehabilitation investments.
    (3) Bonneville will apply a materiality threshold of 2.5 percent 
change in a utility's Base Period ASC to determine when a change in ASC 
will be allowed for resource additions or reductions. Bonneville will 
allow a utility to submit stacks of individual resources that, when 
combined, meet the materiality threshold. However, each resource in the 
stack must result in an increase of Base Period ASC of 0.5 percent or 
more.
    (4) At the time the utility submits its Appendix 1 filing, the 
utility will provide its forecast of major new resource addition(s) and 
all associated costs. The forecast will cover the period from the end 
of the Base Period to the end of the Exchange Period.
    (5) Bonneville will calculate new transmission wheeling revenues 
associated with new transmission investment using the following 
formula:

NTWR = WR (before additions) * [NTP (before additions) + NTA) NTP 
(before additions)]

Where:

NTWR = New transmission wheeling revenues
WR (before additions) = wheeling revenues (before additions)
NTP (before additions) = Net Transmission Plant (before additions)
NTA = new transmission additions

    (6) The forecast of the major new resource costs to be included in 
the utility's Exchange Period ASC will be reviewed and determined 
during the Review Period.
    (7) All major new resources included in an ASC calculation prior to 
the start of the Exchange Period will be projected forward to the 
midpoint of the Exchange Period.
    (8) For each major new resource addition forecast to be available 
to meet regional retail load during the Exchange Period, Bonneville 
will calculate the difference in ASC between the ASC without the new 
resource and the ASC with the new resource (the ASC delta) at the 
midpoint of the Exchange Period.
    (9) When the resource comes online, Bonneville will add the ASC 
delta to the utility's existing ASC to determine its new ASC.
    (10) The steps in paragraphs (c)(3) through (c)(9) of this section 
will be used for resources that are sold, transferred, or retired.
    (11) Bonneville will escalate the Base Period average per-MWh cost 
of Distribution Plant forward to the midpoint of the Exchange Period, 
and use the escalated average cost to determine the distribution-
related cost of meeting load growth since the Base Period. This cost 
will be included in the Exchange Period ASC.
    (12) Bonneville will issue procedural rules to ensure the 
confidentiality of information provided by utilities regarding any new 
major resource additions as part of its review process. Bonneville will 
provide parties with an opportunity to comment on the rules prior to 
their implementation in the review process. Failure to provide needed 
information may result in exclusion of the related costs from the 
utility's ASC. However, as is the case for other utilities that do not 
have major resource additions in a particular year, load growth will be 
assumed to be met with purchases in the wholesale market, as described 
in paragraph (e) of this section. What the utility loses by not 
supplying confidential resource data is the difference between the cost 
of the resource and the price of electricity in the wholesale market.
    (d) Forecasted Contract System and Exchange Load. All utilities are 
required to provide a forecast of their Contract System Load and 
associated Exchange Load, as well as a current distribution loss study 
as described in endnote e/ of Appendix 1, with their Appendix 1 
listing. The load forecast for Contract System Load and Exchange Load 
will be

[[Page 60113]]

provided on a monthly basis for the Exchange Period.
    (e) Load Growth not met by new resource additions. All forecast 
load growth not met by new resource additions will be met by purchased 
power at the forecasted utility-specific, short-term purchased power 
price.
    (1) The utility's forecast load growth will be met with market 
purchases priced at the utility's forecast short-term, purchased power 
price unless the utility forecasts major resource additions.
    (2) In the event of major resource additions, forecast load growth 
will be met by the new resource. If the new resource is less than total 
forecast load growth, the unmet load growth will be met with market 
purchases priced at the utility's forecast short-term, purchased power 
price.
    (3) In the event that the power provided by a new resource exceeds 
the utility's forecast load growth, the excess will be sold as surplus 
power into the market, and priced at the utility's forecast sales for 
resale price as determined in paragraph (b) of this section.
    (f) Changes to service territory. In the event a utility forecasts 
that it will acquire a new service territory, or lose a portion of its 
service territory, and the resulting change in ASC falls within the 2.5 
percent or greater materiality threshold, the utility will submit two 
ASC filings.
    (1) A Base Period ASC that does not reflect the acquisition or loss 
of service territory; and
    (2) A second filing that incorporates the following:
    (i) The forecast of the increase or reduction in Contract System 
Load associated with the acquisition or reduction in service territory.
    (ii) The forecast of the increase or reduction in Contract System 
Costs associated with the acquisition or relinquishment of the service 
territory.
    (iii) In addition to including the forecast of capital and 
operating cost increases or reductions associated with the change in 
service territory, the utility must forecast the changes in purchased 
power expense, sales-for-resale credit and other costs based on the 
changes in the service territory.
    (iv) Because the date of the actual change to the utility's service 
territory could differ from the forecast date used to determine the ASC 
during the Review Period, Bonneville will not adjust the utility's ASC 
until the change in service territory takes place.
    (g) ASC determination for customer-owned utilities that elect to 
execute Regional Dialogue High Water Mark contracts. Bonneville will 
use the following approach:
    (1) Use the RHWM System Load as determined in the Tiered Rates 
methodology process.
    (2) Determine the RHWM Exchangeable Load (Residential/Small Farm 
Load).
    (3) During the ASC review process, the utility must submit the data 
necessary to determine the fully-allocated unit cost of resources in 
excess of the resource amounts used to calculate its CHWM.
    (4) Calculate the utility's total unadjusted Contract System Cost.
    (5) Calculate a load growth credit, i.e., {(Current System Load 
minus RHWM System Load) * Unit costs from paragraph (g)(3) of this 
section{time} .
    (6) Total Exchange Contract System Cost = Total Unadjusted Contract 
System Cost minus load growth revenue credit from paragraph (g)(5) of 
this section.
    (7) HWM Average System Cost = Total Exchangeable Contract System 
Cost/RHWM System Load.
    (h) Filing of Appendix 1. Utilities must file ASC information by 
June 1 each year, as required in Sec.  301.2, for Bonneville's review 
and determination of a Base Period ASC. Utilities will file multiple, 
contingent, Base Period ASC filings to reflect changes to service 
territories as required in paragraph (f) of this section.

Sec.  301.6  Change in Average System Cost methodology.

    (a) The Administrator, at his or her discretion, or upon written 
request from three-quarters of the utilities that are parties to 
contracts authorized by section 5(c) of the Northwest Power Act, or 
from three-quarters of Bonneville's preference customers, or from 
three-quarters of Bonneville's direct-service industrial customers may 
initiate a consultation process as provided in section 5(c) of the 
Northwest Power Act. After completion of this process, the 
Administrator may file the new ASC methodology with the Commission. 
However, the Administrator will not initiate any consultation process 
until one year of experience has been gained under the then-existing 
ASC methodology, one year after the then-existing ASC methodology is 
adopted by Bonneville and approved by the Commission, through interim 
or final approval, whichever occurs first.
    (b) The Administrator may, from time to time, issue interpretations 
of the ASC methodology. The Administrator may modify the 
functionalization code of any Account to comply with the limitations 
identified in section 5(c)(7)(A)-(C) of the Northwest Power Act or to 
conform to Commission revisions to the Uniform System of Accounts.

Sec.  301.7  Sample time line review procedures.

    (a) Bonneville's ASC review process of the utilities' Appendix 1 
occurs only in the year before Bonneville establishes new Wholesale 
Power Rate Schedules. However, utilities are required to file an 
Appendix 1 by June 1 of each year so that Bonneville can maintain 
current data.
    (b) The following schedule is a generic schedule that is 
representative of the time line for the ASC review process. Each spring 
in the year prior to Bonneville's implementation of new Wholesale Power 
Rates, Bonneville will post a detailed schedule incorporating the 
applicable holidays and weekends. Deadlines end at 5 p.m., Pacific 
Prevailing Time, of the due date.
    (1) June 1--Utilities file electronic Appendix 1s with Bonneville.
    (2) June 7--Deadline to file petitions to intervene with 
Bonneville.
    (3) June 10--Bonneville grants or denies petitions to intervene.
    (4) June 11--Begin Data Request period.
    (5) TBD--Workshop(s) on utilities' Appendix 1 filings.
    (6) Aug 22--End Data Request period.
    (7) Aug 27--Deadline for Bonneville's and parties' issue lists on 
utilities' filings.
    (8) Sept 10--Deadline for reply issue lists from all parties on 
utilities' filings.
    (9) Sept 16--Workshop to discuss issue lists on utilities' filings.
    (10) Sept 19--Deadline to request oral argument.
    (11) Sept 22--Bonneville grants or denies requests for oral 
argument.
    (12) Oct 1--Oral argument (if granted).
    (13) Oct 19--Bonneville publishes draft ASC Report.
    (14) Nov 1--Deadline for utilities' and parties' comments on draft 
ASC Report.
    (15) Nov 14--Administrator issues final ASC Report.

Sec.  301.8  Appendix 1 instructions.

    (a) Appendix 1 is the form on which a utility reports its Contract 
System Costs, Contract System Loads, and other necessary data for the 
calculation of ASC. Appendix 1 is an electronic template consisting of 
seven schedules and several supporting files that must be completed by 
the utility in accordance with these instructions and the provisions of 
the endnotes following the schedules.
    (b) Appendix 1 filings must be accompanied by an attestation 
statement

[[Page 60114]]

of the Chief Financial Officer of the utility or other responsible 
official who possesses the financial and accounting knowledge necessary 
to complete the attestation statement.
    (c) The primary source of data for the investor-owned utilities' 
Appendix 1 filings is the utility's prior year Form 1 filing with the 
Commission. Any items not applicable to the utility must be identified.
    (d) For consumer-owned utilities that do not follow the 
Commission's Uniform System of Accounts, filings must include 
reconciliation between utility accounts and the items allowed as 
Contract System Costs. In addition, the cost-of-service report must be 
reviewed by an independent accounting or consulting firm. The cost-of-
service report must be accompanied by a report from an independent 
accounting firm or consulting firm that outlines the review work that 
was performed in preparing the cost-of-service report along with an 
assurance statement that the information contained in the cost-of-
service report is presented fairly in all material respects.
    (e) The Appendix 1 template is available electronically at http://
www.bpa.gov/corporate/finance/ascm/, or its successor site. The primary 
schedules are:

(1) Schedule 1: Plant Investment/Rate Base
(2) Schedule 1A: Cash Working Capital
(3) Schedule 2: Capital Structure and Rate of Return
(4) Schedule 3: Expenses
(5) Schedule 3A: Taxes
(6) Schedule 3B: Other Included Items
(7) Schedule 4: Average System Cost

    (f) The filing utility must reference and attach work papers, 
documentation, and other required information that supports costs and 
loads, including details of allocation and functionalization. All 
references to the Commission's Accounts are the Commission's Uniform 
System of Accounts as of July 1, 2006, or as amended by subsequent 
Commission actions. The costs includable in the attached schedules are 
those includable by reason of the definitions in the Commission's 
Accounts. If the Commission's Accounts are later revised or renumbered, 
any changes will be incorporated into Appendix 1 by reference, except 
to the extent Bonneville determines that a particular change results in 
a change in the type of costs allowable for Residential Exchange 
Program purposes. In that event, Bonneville will address the changes, 
including escalation rules, in its review process for the following 
Exchange Period.
    (g) Bonneville may require a utility to account for all 
transactions with affiliated entities as though the affiliated entities 
were owned in whole or in part by the utility, if necessary, to 
properly determine and/or functionalize the utility's costs.
    (h) A utility operating in more than one Pacific Northwest 
Jurisdiction must file one Appendix 1.
    (i)(1) A utility operating in jurisdictions outside the Pacific 
Northwest Jurisdiction must allocate its total system costs among its 
jurisdictions within the Pacific Northwest and outside the Pacific 
Northwest in accord with the same allocation methods and procedures 
used by the Regulatory Body(ies) to establish jurisdictional costs and 
resulting revenue requirements. The utility's Appendix 1 filing must 
include details of the allocation.
    (2) The allocation must exclude all costs of additional resources 
used to meet loads outside the region, as required by section 5(c)(7) 
of the Northwest Power Act. All schedule entries and supporting data 
must be in accord with Generally Accepted Accounting Principles and 
Practices as these principles and practices apply to the electric 
utility industry.
    (j) A utility must file an attestation statement with each Appendix 
1 filing and supporting documentation for each Review Period.

Sec.  301.9  Functionalization of Average System Cost methodology.

    (a) Functionalization of each account included in a utility's ASC 
must be according to the functionalization prescribed in Table 1, 
Functionalization and Escalation Codes. Direct analysis on an account 
may be performed only if Table 1 states specifically that a utility may 
perform a direct analysis on the account with the exception of 
conservation costs. Utilities will be able to functionalize all 
conservation-related costs to Production, regardless of the Account in 
which they are recorded. The direct analysis must be consistent with 
the directions provided in this section.
    (b) The functionalization codes are:

(1) DIRECT--Direct Analysis.
(2) PROD--Production.
(3) TRANS--Transmission.
(4) DIST--Distribution/Other.
(5) PTD--Production, Transmission, Distribution/Other Ratio.
(6) TD--Transmission, Distribution/Other Ratio.
(7) GP--General Plant Ratio.
(8) GPM--General Plant Maintenance Ratio.
(9) PTDG--Production, Transmission, Distribution/Other, General Plant 
Ratio.
(10) LABOR--Labor Ratio.

    (c) Functionalization process.
    (1) Functionalization of certain accounts may be based on direct 
analysis or with a default ratio associated with that specific account 
as shown in Table 1. Once a utility uses a specific functionalization 
method for an account, the utility may not change the functionalization 
for that account without prior written approval from Bonneville.
    (2) The utility must submit with its Appendix 1 all work papers, 
documents, or other materials that demonstrate that the 
functionalization under its direct analysis assigns costs based upon 
the actual and/or intended functional use of those items. Failure to 
submit the documentation will result in the entire account being 
functionalized to Distribution/Other, or Production, or Transmission, 
as appropriate.
    (d) Functionalization methods.
    (1) Direct analysis, if allowed or required by Table 1, assigns 
costs to the Production, Transmission, and/or Distribution function of 
the utility. The only exception to this requirement is for 
conservation-related costs. Utilities will be able to identify and 
functionalize to Production any conservation-related costs, 
irrespective of the Account in which they are recorded. The analysis is 
subject to Bonneville review and approval. Once a utility uses a 
specific functionalization method for an Account, the utility may not 
change the functionalization for that Account without prior written 
approval from Bonneville.
    (2) Bonneville will not allow utilities to use a combination of 
direct analysis and a prescribed functionalization method for the same 
Account. The utilities can develop and use a functionalization ratio, 
or use a prescribed functionalization method if the utility through 
direct accounts can justify how the ratio reflects the functional 
nature of the costs included in any Account or cost item being 
functionalized by the ratio.
    (3) Utilities that wish to include advertising and promotion costs 
related to conservation will use direct analysis. If a utility records 
conservation costs in an Account that is normally functionalized to 
Distribution/Other, the utility will identify and document the 
conservation-related costs included in the Account, and the balance of 
the costs will be functionalized to Distribution/Other. The presence of 
conservation-related costs in an

[[Page 60115]]

Account does not authorize the utility to perform a direct analysis on 
the entire Account. This option allows a utility to assign costs in the 
specified Account to Production, Transmission and/or Distribution/Other 
based on analysis and support from the utility that demonstrates the 
cost assignment is appropriate. The utility must submit with its ASC 
filing all work papers, documents, and other materials that demonstrate 
the functionalization contained in its direct analysis and assigns 
costs based upon the actual and/or intended functional use of those 
items. Failure to submit the documentation will result in the entire 
account being functionalized to Distribution/Other for all schedules 
with the exception of items included in Schedule 3B, Other Included 
Items, where certain accounts must be functionalized to Production as 
appropriate.
BILLING CODE 6717-01-P

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Table 1 to Part 301--Functionalization and Escalation Codes
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Appendix 1 to Part 301--Bonneville Power Administration Residential 
Purchase and Sales Agreement
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Appendix 2 to Part 301--Chief Financial Officer Attestation
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[FR Doc. E8-23676 Filed 10-9-08; 8:45 am]

BILLING CODE 6717-01-C