[Federal Register Volume 73, Number 198 (Friday, October 10, 2008)]
[Rules and Regulations]
[Pages 60105-60151]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-23676]
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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: [email protected].
Julia A. Lake (Legal Information), Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426, Phone: 202-
502-8370, e-mail: [email protected].
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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
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
[[Page 60116]]
Table 1 to Part 301--Functionalization and Escalation Codes
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[[Page 60120]]
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[[Page 60121]]
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Appendix 1 to Part 301--Bonneville Power Administration Residential
Purchase and Sales Agreement
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[[Page 60122]]
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[[Page 60146]]
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[[Page 60147]]
[GRAPHIC] [TIFF OMITTED] TR10OC08.031
Appendix 2 to Part 301--Chief Financial Officer Attestation
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[[Page 60148]]
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[[Page 60149]]
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[[Page 60150]]
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[[Page 60151]]
[FR Doc. E8-23676 Filed 10-9-08; 8:45 am]
BILLING CODE 6717-01-C