20061006notice_of_modified_procedure_order_no_30146.pdf

Office of the Secretary
Service Date
October 6, 2006
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'
CONSIDERATION OF THE FIVE
AMENDMENTS TO SECTION 111 OF THE
PUBLIC UTILITY REGULATORY
POLICIES ACT OF 1978 (PURP
CONTAINED IN THE ENERGY POLICY
ACT OF 2005
NOTICE OF
MODIFIED PROCEDURE
CASE NO. GNR-06-
ORDER NO. 30146
On July 28, 2006, the Commission issued a Notice of Inquiry to consider the five
new" PURPA standards contained in the Energy Policy Act of 2005. More specifically, the
Energy Policy Act (EP A) amended Section III of the Public Utility Regulatory Policies Act of
1978 (PURP A) by adding five new federal ratemaking standards for electric utilities. The five
new PURP A standards are: net metering; fuel source diversity; fossil fuel generation efficiency;
time-based metering and communications ("Smart Metering ); and interconnection services to
customers with onsite generating facilities. The Commission directed the three largest electric
utilities (Avista, Idaho Power and Rocky Mountain Power) to answer a series of questions set out
in the initial Notice. The Notice required that the utilities serve their comments on a service list
of interested persons.
The Notice also scheduled a public workshop that was convened on September 13
2006. The purpose of the workshop was to review the utilities' responses to the questions in the
Commission s Notice. The Commission also sought to determine whether there was consensus
among the participants about whether the Commission: (1) had already adopted the standards;
(2) should adopt the federal standards or comparable standards, if not already adopted; or (3)
should not implement the federal standards. The Commission also indicated in the initial Notice
that it would seek additional written comments following the public workshop. This Notice
invites the second round of comments regarding the five PURP A standards.
BACKGROUND
This is not the first time that Congress has required state commissions to examine
national regulatory standards. In 1978 Congress enacted PURP A to encourage the conservation
of energy supplied and to promote the optimum efficiency of utility resources. Order No. 30108
at 2. The five new standards address energy efficiency, metering and customer generation.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
Although the EP A requires the Commission to undertake a review of the new federal
standards, the Act does not compel the Commission to adopt the standards. PURP A recognizes
that nothing "prohibits any State regulatory authority. . . from making any determination that
is not appropriate to implement any such standard. . .." Order No. 30108 at citing 16 U.C. ~
2621(a) (emphasis added). The EPA also recognizes that a state regulatory commission may
have already implemented the new federal standards or comparable standards in prior
proceedings. 16 U.C. ~ 2622(d)-(f). If a State has already reviewed a new standard - by
implementing the standard/comparable standard or has considered the standard but declined
implementation - then no further action is necessary. Id.; 16 U.C. ~ 262l(c)(l).
In undertaking our review of the five federal standards PURP A outlines the
procedural requirements that the Commission must follow. The Commission shall issue a public
notice of its review proceeding and make its determination regarding each of the five standards
for each regulated utility: (1) in writing; (2) based upon findings and evidence presented in the
proceeding; and (3) make its findings available to the public. 16 U.C. ~ 2621(b).
THE PUBLIC WORKSHOP
The following parties attended and participated in the public workshop: A vista
Idaho Power, Rocky Mountain Power, Hunt Technologies, the Industrial Customers of Idaho
Power, Distribution Control Systems, John Weber, Jay Blackhurst, and the Commission Staff.
The participants reviewed each of the five federal standards and the utilities' responses to the
questions set out in the Commission s Notice of Inquiry. As described in greater detail below
the participants reached consensus that the Commission has already implemented four of the five
federal PURP A standards.
F or purposes of this round of comments, the five federal standards are listed below as
set out in the EP A and the Commission s Notice of Inquiry issued July 28, 2006. Following
each standard is a brief "discussion" of the standard and the list of initial questions put to each
utility. Both the discussion and the list of questions were contained in the initial Notice. See
Order No. 30108. After the list of questions, the Commission has summarized the utilities
responses and provided a summary of the workshop discussions. The utilities' entire comments
are available for public review during regular business hours at the Commission s offices and are
also available on the Commission s website at www.puc.idaho.gov under the "File Room" icon.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
Click on "Electric Cases " and then click on the case number shown on the first page of this
document.
THE FIVE FEDERAL STANDARDS
Net Metering
(11) Net Metering. Each electric utility shall make available upon request net
metering service to any electric consumer that the electric utility serves. For
purposes of this paragraph, the term "net metering service" means service to
an electric consumer under which electric energy generated by that electric
consumer from an eligible on-site generating facility and delivered to the
local distribution facilities may be used to offset electric energy provided by
the electric utility to the electric consumer during the applicable billing
period.
1. Commission Discussion. Net metering generally refers to customers generating
their own electricity with any excess being delivered to the utility s distribution system. In
essence, the customer s utility meter records the flow of electricity to and from the customer.
In 1997 the Commission approved its first net metering tariff for Idaho Power
(Schedule 84). Order No. 26750. In August 2002, the Commission issued Order No. 29094
expanding net metering to all Idaho Power customers and increasing the size of the permissible
generating facilities. A vista and Rocky Mountain also have net metering tariffs (Schedules 62
and 135 , respectively).
We direct each utility to answer the following questions:
1. Briefly describe your net metering program.
2. Are all customers eligible to participate in your net metering program?
not, why not? Are there limitations on the number of participating
customers or the amount of net metering generation? Are there
restrictions regarding the type of net metering generation?
3. State the number of net metering customers by customer class.
4. State the amount of net metering generation by customer class.
1 On June 19, 2006, Avista filed a revised Application seeking authority to amend its net metering provisions and
move the net metering provisions to Schedule 63. Case No. A VU-06-4. In Order No. 30111 issued August 10
2006, the Commission approved Avista s Application.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
5. Does your current or proposed net metering tariff/schedule meet the
federal net metering standard set out above? If not, should the
Commission adopt this standard or a comparable standard?
2. Utilities' Responses . The utilities responded that they each have a net metering
program in place that is available to all customers. The framework of each utility s net metering
program is similar in that they: (1) offer net metering to customers using solar, wind
hydropower, biomass or fuel cells; (2) limit the program to .10% of their retail peak generation;
(3) limit residential customers to facilities no greater than 25 kW; and (4) restrict anyone
customer from generating more than 20% of such peak generation. A vista has four residential
net metering customers in Idaho producing 16 000 kW during 2005. The Company s net
metering Schedule 63 was most recently approved August 1 , 2006.
Rocky Mountain currently has one residential net metering customer but has several
potential projects pending. The Company s net metering generation ceiling is 714 kW. The
Company s net metering Schedule is 135.
Idaho Power has 20 residential customers, 4 small business customers, and 2 large
business customers. The 24 smaller customers generated 397 255 kW in 2005. The Company
has an application pending to modify its net metering Schedule 84. In Case No. IPC-06-
Idaho Power proposes to change the net credit for net metering generation to 85% of the avoided
cost contained in Schedule 84. Comments in that proceeding are due October 13, 2006.
3. Workshop Comments. The utilities and the participants generally agreed that the
utilities' net metering programs meet the federal net metering standard. One participant did
express a concern that existing net metering customers may be detrimentally affected if they
installed generating facilities based upon existing net metering rate structures, and the utility
subsequently changes the program.
Fuel Sources
(12) Fuel Sources. Each electric utility shall develop a plan to minimize
dependence on 1 fuel source and to ensure that the electric energy it sells to
consumers is generated using a diverse range of fuels and technologies
including renewable technologies.
1. Commission Discussion. This standard may have already been implemented in
Idaho. In Order No. 22299 , we required Avista, Idaho Power, and PacifiCorp (or their
predecessors) to bi-annually prepare and file an integrated resource plan (IRP). Each IRP
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
describes the Company s expectation for load growth and provides an overview of available
resource options, including "conservation resources, demand-side resources and other potentially
low life-cycle-cost resources." Order No. 22299.
A review of the current IRPs reveals that each utility employs a diverse range of
generating resources including renewables. For example, Rocky Mountain s current 2004 IRP
reflects the addition of demand-side management (DSM) resources, coal and natural gas thermal
generation, combined heat and power generation, wind, geothermal, distributed generation, etc.
Notice of Filing, Case No. PAC-05-2 (June 30, 2005); see also Order Nos. 29614 (Idaho
Power) and 29887 (Avista). Thus, it appears that the IRP process minimizes dependence on a
single fuel source and our utilities employ a diverse array of fuels and technologies, including
renewables. The utilities should comment on whether this standard. has already been
implemented by the Commission as part of the IRP process.
2. Utilities' Responses . The utilities observed that the Commission s Order No.
30108 asked whether this standard may already have been implemented as part of the IRP
process. Each utility indicated that fuel source diversity is part of their respective IRPs. The
utilities concluded that this new PURP A standard has already been implemented by the
Commission as part of the IRP process.
3. Workshop Comments . The participants agreed that diversifying generating fuel
sources was evident by each utility's resource stack in their IRPs. Consequently, the participants
agreed that the Commission has already implemented this federal standard.
Fossil Fuel Generation Efficiency
(13) Fossil Fuel Generation Efficiency. Each electric utility shall develop
and implement a 10-year plan to increase the efficiency of its fossil fuel
generation.
1. Commission Discussion. This standard promotes the efficiency of fossil fuel
generating facilities. All three utilities have fossil fuel (coal and natural gas) generation
facilities. Increasing the efficiency of existing generating resources may already be a part of the
IRP process. The utilities should comment on whether increasing fuel efficiency is already a
part of their respective IRPs. If not, should the Commission require that the issue of fossil fuel
efficiency be included in the bi-annual IRPs?
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
2. Utilities' Responses . The three utilities assert that fossil fuel efficiency is a part of
their IRPs. F or example, A vista noted that examining fossil fuel efficiency is a part of the
ongoing review process performed by the Colstrip owners committee. Idaho Power noted that
since 1995 it has implemented 18 MW of generation efficiency upgrades. The utilities
maintained the Commission need not take further action on this standard because it has already
been implemented.
3. Workshop Comments. The participants did not disagree with the utilities
assessment that generation efficiency is part of their respective IRPs. The Industrial Customers
of Idaho Power did note that the Commission may want to require future IRPs to explicitly
address this issue instead of being subsumed in the IRP.
Smart Metering
(14) Time-based metering and communications.
(A) Not later than 18 months after the date of enactment of this
paragraph, each electric utility shall offer each of its customer classes
and provide individual customers upon customer request, a time-
based rate schedule under which the rate charged by the electric
utility varies during different time periods and reflects the variance, if
any, in the utility s cost of generating and purchasing electricity at the
wholesale level. The time-based rate schedule shall enable the
electric consumer to manage electric use and cost through advanced
metering and communications technology.
(B) The type of time-based rate schedules that may be offered
under the schedule referred to in subparagraph (A) include, among
others -
(i) time-of-use pricing whereby electricity prices are set for a
specific time period on an advanced or forward basis
typically not changing more often than twice a year, based on
the utility cost of generating and/or purchasing such
electricity at the wholesale level for the benefit of the
consumer. Prices paid for energy consumed during these
periods shall be pre-established and known to consumers in
advance of such consumption, allowing them to vary their
demand and usage in response to such prices and manage
their energy costs by shifting usage to a lower cost period or
reducing their consumption overall;
(ii) critical peak pricing whereby time-of-use prices are in
effect except for certain peak days, when prices may reflect
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
the costs of generating and/or purchasing electricity at the
wholesale level and when consumers may receive additional
discounts for reducing peak period energy consumption;
(iii) real-time pricing whereby electricity prices are set for a
specific time period on an advanced or forward basis
reflecting the utility s cost of generating and/or purchasing
electricity at the wholesale level, and may change as often as
hourly; and
(iv) credits for consumers with large loads who enter into pre-
established peak load reduction agreements that reduce a
utility s planned capacity obligations.
(C) Each electric utility subject to subparagraph (A) shall provide
each customer requesting a time-based rate with a time-based meter
capable of enabling the utility and customer to offer and receive
such rate, respectively.
1. Commission Discussion. As was the case with net metering, this Commission
and the utilities have previously addressed Smart Metering (time-based metering and
communications). For example, Avista began installing Advanced Meter Reading (AMR)
devices on all of its Idaho electric and gas meters in 2005. Order No. 24602 at 51. Rocky
Mountain has offered its residential customers time-of-day service (Schedule 36) for many years.
For its part, Idaho Power has implemented an AMR pilot program for more than 23 000
residential customers that provides two optional services - time-variant pricing and air
conditioner cycling. Order No. 29959. When authorizing these Smart Metering programs, the
Commission stated that the implementation of the programs should be prudent and cost-
effective.
A recent Federal Energy Regulatory Commission Staff Report indicated that Idaho
ranks fifth (at 16.2%) in the percentage of customers with "advanced metering.2 Given this
brief background information, the Commission directed the utilities to address the following
questions:
1. Briefly describe your Smart Metering programs previously implemented.
For each program indicate the number of customers by class eligible to
participate in the program and the number of customers actually
2 Slide 7 at http://www.ferc.gov/whats-new/headlines/2006/2006-3/07-20-06-demand-response.pdf.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
participating in each program. What are the differences between your
programs and the federal standard, including costs and benefits?
2. Should the Commission adopt the Smart Metering standard by requiring
each utility to offer by February 8, 2007, a time-based rate to each
customer class and the necessary time-based metering to individual
customers upon request? Why, or why not?
3. Should the Commission adopt the time-based metering and
communications standard by applying the same requirements to all
utilities?
4. Which, if any, of the four listed types of time-based rate schedules should
the Commission require? Should the same types of rate schedules be
required of all utilities and for all customer classes?
5. Are there other issues the Commission should consider in reviewing this
standard?
2. Utilities' Responses . This standard generated the greatest amount of comments
from both the utilities and the participants at the public workshop. All of the utilities indicated
that they have started "Smart Metering" programs and have partially implemented the standards.
In particular, Avista noted that it is in the second year of a four-year deployment of AMR meters
for all of their Idaho customers. In answer to the Commission s second question, Avista
indicated that it could not offer time-based rates by either February or August 2007.3 Avista
recommended that the Commission not adopt this standard for several reasons. First, A vista
indicated that it would not have all of its meters installed by August 2007. Second, the Company
stated that it did not have implementing tariffs, data storage, and necessary billing changes to
support time-based rates. The Company estimated that the billing and data storage costs alone
would be approximately $22 million. Finally, the Company asserted that it was not cost
effective to offer time-based rates to all classes of customers, but that it might be effective for
large customers.
Rocky Mountain declared that it currently offers optional time-of-day service to all
residential and distribution voltage customers. It maintained that its time-of-day service
complies with the spirit of the standard. The Company indicated it was neither achievable nor
3 The workshop participants recognized that there was confusion in the industry of exactly when Congress required
this standard to be reviewed and/or implemented. One portion of the Energy Policy Act indicates a deadline for this
standard of February 8 2007 while another section indicates August 8, 2007. The participants generally concluded
that the implementation date for this standard be August 8, 2007.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
reasonable to adopt this standard by February 2007. Rocky Mountain did agree with the
Commission s statement that all Smart Metering programs should "be prudent and cost
effective." Rocky Mountain Comments at 7; Order No. 30108 at 7.
Idaho Power commented that it is steadily deploying smart meters so that the costs of
deployment are commensurate with the benefits. The Company reported it has 123 industrial
customers (Schedule 19) on time-of-use; 130 large business customers (Schedule 9) on time-of-
use; and 117 irrigation customers on time-of-use (but not ARM meters). The Company has
approximately 25 500 AMR meters currently installed. It too noted that it would not be able to
implement this standard for all customers by February 2007. All three utilities indicated that
adoption of Smart Metering policies should be based on a company-by-company basis and
implemented in situations where the cost and benefits are reasonable.
3. Workshop Comments Representatives of Hunt Technology agreed with the
utilities that there should be specific Smart Metering policies for each utility based upon their
distinct territories and customer base. The participants recognized that Idaho ranks fifth
nationally in the percentage of customers with "advanced meters.See Order No. 30108 at 7.
the Commission were to consider greater deployments of smart meters, Hunt suggested that the
policy should be guided by: (1) what is in the best operational interest of the utility; (2) what is
in the best interest of ratepayers; and (3) what functionalities work for each utility.
Interconnection
Section 1254(a) establishes an interconnection standard for customers with on-site
generating facilities. This standard states:
(15) Interconnection. Each electric utility shall make available, upon request
interconnection service to any electric consumer that the electric utility
serves. For purposes of this paragraph, the term "interconnection service
means service to an electric consumer under which an on-site generating
facility on the consumer s premises shall be connected to the local
distribution facilities. Interconnection services shall be offered based upon
the standards developed by the Institute Of Electrical And Electronics
Engineers: IEEE Standard 1547 for Interconnecting Distributed Resources
with Electric Power Systems, as they may be amended from time to time.
addition, agreements and procedures shall be established whereby the
services offered shall promote current best practices of interconnection for
distributed generation, including but not limited to practices stipulated in
model codes adopted by associations of state regulatory agencies. All such
agreements and procedures shall be just and reasonable, and not unduly
discriminatory or preferential.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
1. Commission Discussion.This standard encourages state commissions to adopt
best practices" to promote the interconnection of distributed generation facilities. Distributed
generation generally refers to a customer s on-site generating facility that may provide
generation (i., interconnects) to the local distribution system as opposed to serving the utility
transmission system. See Order No. 29260 at 6-7 (comparing net metering and distributed
generation); 42 U.C. ~ 16197(g)(3). The federal standard adopts interconnection standards
published by the Institute of Electrical and Electronics Engineers (IEEE) and references other
model codes adopted by state regulatory agencies.
IEEE Standard No. 1547-2003 (July 2003) is intended to provide uniform standards
for interconnecting a customer s on-site "distribution resource" with the local electric power
system. It provides requirements for the performance, operation, testing, maintenance and safety
considerations of the interconnection. Standard 1547-2003 at ~ 1.2. The IEEE Standard is
further intended to apply to all distributed generation technologies with aggregate capacity of 10
MV A or less at interconnection. The standard does not define the maximum distributed
generation capacity for a particular installation. Id. at ~ 1.
1. Should the Commission adopt this standard for interconnecting a
customer s on-site generating facility to local distribution facilities?
2. Do the utilities currently have tariffs, agreements, procedures or
schedules delineating interconnection standards of customer-owned
generating facilities? If yes, where are they located (e., tariffs
schedules, websites, etc.)? Are there limitations on the per customer
capacity or total system capacity of customer-owned generation
facilities? What are the limits?
3. Should the Commission adopt or consider separate interconnection
standards for smaller and larger generating facilities (e., .( 25 kW up to
100 kW, .( IMW ? IMW, or some other limitation)?
4. Should the Commission adopt IEEE Standard 1547?
5. Should the Commission adopt the NARUC Model Interconnection
Procedures and Agreement?
4 In 2003 the National Association of Regulatory Utility Commissioners (NARUC) published a model code entitled
Model Interconnection Procedures and Agreement for Small Distribution Generation Resources." The Model
Procedures and Agreement are available via NARUC's website at:
http://naruc.orglgoto.cfm?retumto=displayindustrynews.cfm& in dustrytop i cn br=3 8 O&page= http://www . naruc. orgl
sociations/l773/files/dgiaip octO3.pdf
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
6. Are there other issues the Commission should consider regarding this
standard?
2. Utilities' Responses . The utilities indicated that for the most part they have
already implemented this federal standard. A vista stated that its interconnection requirements
are contained in its Schedule 70, Part 28 and on its website. It also indicated that it recently
amended its tariff to include the adoption oflEEE Standard 1547. See Order No. 30111 , Case
No. A VU-06-4. In response to the question about whether the Commission should adopt the
NARUC Model Interconnection Procedures and Agreement (the "Model"), the Company
suggested the Commission adopt it as a guideline recognizing that utilities may have particular
problems with certain elements of the Model Agreement. In particular, A vista said that it may
have difficulty providing notice of interruptions seven days in advance.
Rocky Mountain asserted it did not need to adopt IEEE Standard 1547 because the
Company already uses the standard and further noted that it is not applicable to every situation.
The Company s interconnection standards are set out in its net metering Schedule 135 and its
Open Access Transmission Tariff (OA TT) posted on its website. If the Commission wishes to
adopt thresholds for interconnection, then a reasonable breaking point would be 100 kW and less
for net metering and at 100 kW and larger generators may need additional protections. Rocky
Mountain also recommended the Commission consider not adopting the NARUC Model
because: its timelines are too restrictive; it may inadvertently limit due diligence for each plant;
and Idaho is only one of six states where PacifiCorp operates.
Idaho Power indicated that it is in compliance with the federal interconnection
standard except it has not explicitly adopted IEEE Standard 1547. However, it intended to
incorporate this standard. Idaho Power s interconnection policies and practices are contained in
its Schedules 72 and 84; in its Best Practices (website); and in its OA TT. Rather than adopting
standards for certain sized facilities, Idaho Power currently divides facilities into small, medium
and large interconnecting facilities. While Idaho Power did not object to adoption of IEEE
Standard 1547, it asserted the IEEE standard is not applicable to all situations because it applies
to facilities of 10 MY A or less. Turning to the NARUC Model, Idaho Power supported the
model in principle but recognizes that "one size does not fit all." It indicated it will file a new
Schedule 72 (and Schedule 84 for QF) as part of a proposed uniform interconnection agreement
this month in response to FERC's Standards of Conduct.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
3. Workshop Comments. The participants did not voice any disagreement with the
utilities ' comments.
NOTICE OF MODIFIED PROCEDURE
YOU ARE HEREBY NOTIFIED that the Commission has preliminarily determined
that the public interest may not require a formal hearing in this matter and will proceed under
Modified Procedure pursuant to Rules 201 through 204 of the Idaho Public Utilities
Commission s Rules of Procedure, IDAPA 31.01.01.201 through .204. Written comments have
proven to be an efficient means for obtaining public input and participation.
YOU ARE FURTHER NOTIFIED that the Commission invites additional public
comments from the workshop participants and other interested persons on the five federal
standards. In particular, the Commission seeks comments on whether the five federal standards
or comparable standards should be adopted or declined and the reasons supporting such
comments.
YOU ARE FURTHER NOTIFIED that any person desiring to state a position on this
Inquiry may file a written comment in support or opposition with the Commission within 21
days from the service date of this Notice. The comment must contain a statement of reasons
supporting the comment. Persons desiring a hearing must specifically request a hearing in their
written comments.Written comments concerning this Inquiry shall be mailed to the
Commission at the address reflected below:
Commission Secretary
Idaho Public Utilities Commission
PO Box 83720
Boise, ID 83720-0074
Street Address for Express Mail:
472 W. Washington Street
Boise, ID 83702-5983
These comments should contain the case caption and case number shown on the first page of this
document.Persons desiring to submit comments via e-mail may do so by accessing the
Commission s home page located at www.puc.idaho.gov. Click the "Comments and Questions
icon, and complete the comment form, using the case number as it appears on the front of this
document.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
YOU ARE FURTHER NOTIFIED that if no written comments or protests are
received within the time limit set, the Commission will consider this matter on its merits and
enter its Order without a formal hearing. If written comments are received within the time limit
set, the Commission will consider them and, in its discretion, may set the same for formal
hearing.
YOU ARE FURTHER NOTIFIED that the utilities may file a response to any public
comments within 35 days of the date of this Order.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission s jurisdiction under the Energy Policy Act of 2005; Title 61 of the
Idaho Code; and specifically Idaho Code ~~ 61-302, 61-307 , 61-336 , and 61-507.
Commission may enter any final Order consistent with its authority under Title 61.
The
YOU ARE FURTHER NOTIFIED that all proceedings in this matter will be
conducted pursuant to the Commission s Rules of Procedure, IDAPA 31.01.01.000 et seq.
ORDER
IT IS HEREBY ORDERED that persons interested in submitting written comments
regarding the five federal PURP A standards should do so no later than 21 days from the service
date of this Order.
IT IS FURTHER ORDERED that the utilities may, if necessary, file a response to
written comments no later than 35 days from the service date of this Order.
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
....rt..
day of October 2006.
d~R
ATTEST:
Je. D. Jewe
Commission Secretary
bls/GNR-06-02 dh2
NOTICE OF MODIFIED PROCEDURE
ORDER NO. 30146