Sales of Electric Power to the Bonneville Power Administration; Revisions to Average System Cost Methodology, 60105-60151 [E8-23676]
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jlentini on PROD1PC65 with RULES
Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations
mistakenly states that it was ‘‘Added by
SB900–036.’’ Inspection holes at L167 and
R167 were originally specified by SB600N–
036.
(c) Within 25 hours TIS, unless
accomplished previously:
(1) Thoroughly clean all attachment fittings
and the surrounding areas, inspect the area
for cracking, replace the upper right
attachment fitting and all four nut plates, and
paint the area inside of the attachment
fittings in accordance with the
Accomplishment Instructions, paragraph
2.B., of MD Helicopters Service Bulletin
SB600N–043, dated April 13, 2006 (SB600N–
043). If a crack is found in any of the other
three attachment fittings, before further
flight, accomplish the actions described in
paragraph (f) of this AD.
(2) Using a 10x magnifying glass, inspect
the attachment bolts’ threads and shanks for
wear or damage in accordance with
paragraph 2.B., of SB600N–043. If wear or
damage is present, replace the attachment
bolts with airworthy bolts.
(d) Thereafter, at the specified intervals,
remove the plug buttons from the inspection
holes, and using a bright light, inspect the
upper and lower left and upper and lower
right attachment fittings, angles, and nut
plates for a crack by following the
Accomplishment Instruction paragraphs of
SB600N–039, as follows, except you are not
required to contact MDHI to meet the
requirements of this AD.
(1) At intervals not to exceed 25 hours TIS,
through inspection holes at L167 and R167,
inspect the upper left and upper right
attachment fittings, angles, and nut plates by
following the Accomplishment Instructions,
paragraphs 2.B.(2) through 2.B.(4), of
SB600N–039.
(2) At intervals not to exceed 100 hours
TIS, through inspection holes at L166 and
R166, inspect the lower left and lower right
attachment fittings, angles, and nut plates by
following the Accomplishment Instructions,
paragraphs 2.B.(2) through 2.B.(4), of
SB600N–039.
(e) If a crack is found in the upper right
attachment fitting, or in any angle, nut plate,
longeron, or if thread wear or damage is
found on any nut plate or bolt, before further
flight, replace the cracked or worn or
damaged part with an appropriate airworthy
part, or accomplish the actions in paragraph
(f) of this AD. If cracking is found in any of
the other three attachment fittings, before
further flight, accomplish the actions
described in paragraph (f) of this AD.
(f) If required by paragraph (c)(1) of this
AD, or if you make this modification to
comply with paragraph (e) of this AD, modify
the fuselage aft section to strengthen the
tailboom attachments and the upper
longerons by following paragraph 2,
Accomplishment Instructions, of MDHI
TB600N–007, dated January 12, 2004;
TB600N–007, Revision 1, dated April 13,
2006; or TB600N–007, Revision 2, dated
October 5, 2006; except you are not required
to contact the manufacturer. This
modification to the fuselage aft section is
terminating action for the requirements of
this AD.
(g) Within 24 months, modify the fuselage
aft section to strengthen the tailboom
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17:42 Oct 09, 2008
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attachments and upper longerons by
following paragraph 2, Accomplishment
Instructions, of MDHI TB600N–007, Revision
2, dated October 5, 2006, except you are not
required to contact the manufacturer. This
modification to the fuselage aft section is
terminating action for the requirements of
this AD.
(h) To request a different method of
compliance or a different compliance time
for this AD, follow the procedures in 14 CFR
39.19. Contact the Manager, Los Angeles
Aircraft Certification Office, Airframe
Branch, FAA, ATTN: Eric Schrieber,
Aviation Safety Engineer, 3960 Paramount
Blvd., Lakewood, California 90712, telephone
(562) 627–5348, fax (562) 627–5210, for
information about previously approved
alternative methods of compliance.
(i) Inspect, replace, and modify the
fuselage aft section according to the specified
portions of the following MD Helicopters
service information, as applicable.
(1) Service Bulletin SB600N–036, dated
November 2, 2001; incorporated by reference
as of April 29, 2002 (67 FR 17934, April 12,
2002).
(2) Service Bulletin SB600N–039, dated
December 9, 2003; Service SB600N–043,
dated April 13, 2006; and Technical Bulletin
TB600N–007, Revision 1, dated April 13,
2006; incorporated by reference as of April
27, 2006 (71 FR 24808, April 27, 2006).
(3) Technical Bulletin TB600N–007,
Revision 2, dated October 5, 2006;
incorporated by reference as of April 16,
2008 (73 FR 13096, March 12, 2008).
(4) The incorporation by reference of these
documents was approved previously by the
Director of the Federal Register in accordance
with 5 U.S.C. 552(a) and 1 CFR part 51.
(5) Copies of this service information may
be obtained from MD Helicopters Inc., Attn:
Customer Support Division, 4555 E.
McDowell Rd., Mail Stop M615, Mesa,
Arizona 85215–9734, telephone 1–800–388–
3378, fax 480–346–6813, or on the Internet at
https://www.mdhelicopters.com.
(6) Copies may be inspected at the FAA,
Office of the Regional Counsel, Southwest
Region, 2601 Meacham Blvd., Room 663, Fort
Worth, Texas, or at the National Archives
and Records Administration (NARA). For
information on the availability of this
material at NARA, call 202–741–6030, or go
to: https://www.archives.gov/federal_register/
code_of_federal_regulations/
ibr_locations.html.
(j) This amendment becomes effective
on October 27, 2008.
Issued in Fort Worth, Texas, on September
25, 2008.
Mark R. Schilling,
Acting Manager, Rotorcraft Directorate,
Aircraft Certification Service.
[FR Doc. E8–23540 Filed 10–9–08; 8:45 am]
BILLING CODE 4910–13–P
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60105
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.
Federal Energy Regulatory
Commission.
ACTION: Interim rule.
AGENCY:
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.
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: https://
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.
DATES:
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Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations
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.
Background
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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
1 16
U.S.C. 839(c).
2 Id.
3 16
4 Id.
U.S.C. 839c(c)(1).
This rate is generally a lower rate.
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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.
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.
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
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
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)).
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).
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).
10 16 U.S.C. 824, 824d, 824e.
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rates for such sales from the investorowned 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
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.
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.
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
11 Order No. 400, FERC Stats. & Regs. ¶ 30,601 at
31,161.
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.
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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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.
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
15 16
17:42 Oct 09, 2008
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
17. The Commission attaches this
condition with the full awareness that,
16 Order No. 400, FERC Stats. & Regs. ¶ 30,601 at
31,162.
U.S.C. 839e.
VerDate Aug<31>2005
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.
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60107
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
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.
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.
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
17 Id.
18 Regulations Implementing the National
Environmental Policy Act, Order No. 486, FERC
Stats. & Regs. ¶ 30,783 (1987).
19 18 CFR 380.4(a)(15).
20 5 U.S.C. 601–12.
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Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations
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.
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
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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.
24. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
Web site at https://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.
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.
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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19:26 Oct 09, 2008
Jkt 217001
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 https://
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.
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.
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
23 5
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U.S.C. 553(d)93.
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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.
§ 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).
§ 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.
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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 § 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 consumerowned 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:
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(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.
§ 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
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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
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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
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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.
§ 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.
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(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 § 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 (https://
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.
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Access to the information will be
subject to any confidentiality rules or
requirements established by Bonneville.
(3) Day 7. Deadline to file utilityspecific 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
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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.
§ 301.5 Exchange Period Average System
Cost Determination.
(a) Escalation to Exchange Period.
(1) Bonneville will escalate
Bonneville-approved Base Period costs
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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 shortterm 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.
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(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
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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 online, 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)
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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
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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 shortterm, 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-forresale 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 customerowned utilities that elect to execute
Regional Dialogue High Water Mark
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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 fullyallocated 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}.
(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 § 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.
§ 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 threequarters 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 thenexisting 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
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60113
5(c)(7)(A)–(C) of the Northwest Power
Act or to conform to Commission
revisions to the Uniform System of
Accounts.
§ 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.
§ 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
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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-ofservice report is presented fairly in all
material respects.
(e) The Appendix 1 template is
available electronically at https://
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.
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(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.
§ 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.
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(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
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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
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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
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60115
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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Financial Officer Attestation
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60150
Federal Register / Vol. 73, No. 198 / Friday, October 10, 2008 / Rules and Regulations
[FR Doc. E8–23676 Filed 10–9–08; 8:45 am]
FOR FURTHER INFORMATION CONTACT:
BILLING CODE 6717–01–C
40 CFR Part 180
Stephen Schaible, Registration Division
(7505P), Office of Pesticide Programs,
Environmental Protection Agency, 1200
Pennsylvania Ave., NW., Washington,
DC 20460–0001; telephone number:
(703) 308-9362; e-mail address:
schaible.stephen@epa.gov.
[EPA–HQ–OPP–2002–0043; FRL–8376–1]
SUPPLEMENTARY INFORMATION:
ENVIRONMENTAL PROTECTION
AGENCY
I. General Information
Pesticide Tolerance Nomenclature
Changes; Technical Amendments
Environmental Protection
Agency (EPA).
ACTION: Final rule; Technical
Amendments.
jlentini on PROD1PC65 with RULES
AGENCY:
SUMMARY: This document makes minor
technical revisions to the terminology of
certain commodity terms listed under
40 CFR part 180, subparts A, C, and E.
EPA is taking this action to establish a
uniform listing of commodity terms
throughout part 180.
DATES: This regulation is effective
October 10, 2008. Objections and
requests for hearings must be received
on or before December 9, 2008, and
must be filed in accordance with the
instructions provided in 40 CFR part
178 (see also Unit I.C. of the
SUPPLEMENTARY INFORMATION ).
ADDRESSES: EPA has established a
docket for this action under docket
identification (ID) number EPA–HQ–
OPP–2002–0043. To access the
electronic docket, go to https://
www.regulations.gov, select ‘‘Advanced
Search,’’ then ‘‘Docket Search.’’ Insert
the docket ID number where indicated
and select the ‘‘Submit’’ button. Follow
the instructions on the regulations.gov
website to view the docket index or
access available documents. All
documents in the docket are listed in
the docket index available in
regulations.gov. Although listed in the
index, some information is not publicly
available, e.g., Confidential Business
Information (CBI) or other information
whose disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available in the electronic docket at
https://www.regulations.gov, or, if only
available in hard copy, at the OPP
Regulatory Public Docket in Rm. S–
4400, One Potomac Yard (South Bldg.),
2777 S. Crystal Dr., Arlington, VA. The
Docket Facility is open from 8:30 a.m.
to 4 p.m., Monday through Friday,
excluding legal holidays. The Docket
Facility telephone number is (703) 305–
5805.
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A. Does this Action Apply to Me?
You may be potentially affected by
this action if you are an agricultural
producer, food manufacturer, or
pesticide manufacturer. Potentially
affected entities may include, but are
not limited to those engaged in the
following activities:
• Crop production (NAICS code 111).
• Animal production (NAICS code
112).
• Food manufacturing (NAICS code
311).
• Pesticide manufacturing (NAICS
code 32532).
This listing is not intended to be
exhaustive, but rather to provide a guide
for readers regarding entities likely to be
affected by this action. Other types of
entities not listed in this unit could also
be affected. The North American
Industrial Classification System
(NAICS) codes have been provided to
assist you and others in determining
whether this action might apply to
certain entities. If you have any
questions regarding the applicability of
this action to a particular entity, consult
the person listed under FOR FURTHER
INFORMATION CONTACT.
B. How Can I Access Electronic Copies
of this Document?
In addition to accessing an electronic
copy of this Federal Register document
through the electronic docket at https://
www.regulations.gov, you may access
this Federal Register document
electronically through the EPA Internet
under the ‘‘Federal Register’’ listings at
https://www.epa.gov/fedrgstr. You may
also access a frequently updated
electronic version of EPA’s tolerance
regulations at 40 CFR part 180 through
the Government Printing Office’s pilot
e-CFR site at https://www.gpoaccess.gov/
ecfr.
C. Can I File an Objection or Hearing
Request?
Under section 408(g) of FFDCA, any
person may file an objection to any
aspect of this regulation and may also
request a hearing on those objections.
You must file your objection or request
a hearing on this regulation in
accordance with the instructions
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60151
provided in 40 CFR part 178. To ensure
proper receipt by EPA, you must
identify docket ID number EPA–HQ–
OPP–2002–0043 in the subject line on
the first page of your submission. All
requests must be in writing, and must be
mailed or delivered to the Hearing Clerk
as required by 40 CFR part 178 on or
before December 10, 2008.
In addition to filing an objection or
hearing request with the Hearing Clerk
as described in 40 CFR part 178, please
submit a copy of the filing that does not
contain any CBI for inclusion in the
public docket that is described in
ADDRESSES. Information not marked
confidential pursuant to 40 CFR part 2
may be disclosed publicly by EPA
without prior notice. Submit this copy,
identified by docket ID number EPA–
HQ–OPP–2002–0043, by one of the
following methods:
• Federal eRulemaking Portal: https://
www.regulations.gov. Follow the on-line
instructions for submitting comments.
• Mail: Office of Pesticide Programs
(OPP) Regulatory Public Docket (7502P),
Environmental Protection Agency, 1200
Pennsylvania Ave., NW., Washington,
DC 20460–0001.
• Delivery: OPP Regulatory Public
Docket (7502P), Environmental
Protection Agency, Rm. S–4400, One
Potomac Yard (South Bldg.), 2777 S.
Crystal Dr., Arlington, VA. Deliveries
are only accepted during the Docket’s
normal hours of operation (8:30 a.m. to
4 p.m., Monday through Friday,
excluding legal holidays). Special
arrangements should be made for
deliveries of boxed information. The
Docket Facility telephone number is
(703) 305–5805.
II. Background
A. What Action is the Agency Taking?
EPA’s Office of Pesticide Programs
(OPP) has developed a commodity
vocabulary database entitled ‘‘Food and
Feed Commodity Vocabulary.’’ The
database was developed to consolidate
all the major OPP commodity
vocabularies into one standardized
vocabulary. As a result, all future
pesticide tolerances issued under 40
CFR part 180 will use the ‘‘preferred
commodity term’’ as listed in the
aforementioned database. Previously,
seven documents in a series of
documents revising the terminology of
commodity terms currently in
tolerances in 40 CFR part 180 have been
published. Final Rules, revising
pesticide tolerance nomenclature, were
published in the Federal Register on
June 19, 2002 (67 FR 41802) (FRL–
6835–2); June 21, 2002 (67 FR 42392)
(FRL–7180–1); July 1, 2003 (68 FR
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Agencies
[Federal Register Volume 73, Number 198 (Friday, October 10, 2008)]
[Rules and Regulations]
[Pages 60105-60151]
From the Federal Register Online via the Government Printing 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.
-----------------------------------------------------------------------
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: https://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.
---------------------------------------------------------------------------
\1\ 16 U.S.C. 839(c).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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)).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\10\ 16 U.S.C. 824, 824d, 824e.
\11\ Order No. 400, FERC Stats. & Regs. ] 30,601 at 31,161.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\15\ 16 U.S.C. 839e.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\16\ Order No. 400, FERC Stats. & Regs. ] 30,601 at 31,162.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\17\ Id.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\18\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
\19\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\20\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
24. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at https://
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 https://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 (https://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
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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 pr