20060728notice_of_inquiry_order_no_30108.pdf

Office of the Secretary
Service Date
July 28, 2006
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'
CONSIDERATION OF THE FIVE CASE NO. GNR-06-
AMENDMENTS TO SECTION 111 OF THE
PUBLIC UTILITY REGULATORY NOTICE OF INQUIRY
POLICIES ACT OF 1978 (pURP
CONTAINED IN THE ENERGY POLICY NOTICE OF
ACT OF 2005 MODIFIED PROCEDURE
NOTICE OF
PUBLIC WORKSHOP
ORDER NO. 30108
On August 8, 2005 , the President signed into law the Electricity Modernization Act
of 2005 (the "Modernization Act") as Title XII of the Energy Policy Act of 2005 , Pub. Law No.
109-58. Among other things, the Modernization Act amended Section 111 of the Public Utility
Regulatory Policies Act of 1978 (PURPA)l by adding five new federal ratemaking standards for
electric utilities. The Modernization Act further amended PURP A Sections 112 and 115 to
require that state regulatory commissions determine whether they should adopt the five PURP A
standards as requirements for regulated electric utilities. 16 U.C. ~ 2621(a). As described in
greater detail below, 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 service to customers with on-site generating facilities.
The Commission initiates this proceeding to consider the five new PURP A standards
contained in the Modernization Act. As set out in greater detail below, the Commission invites
our three applicable utilities 2 interested stakeholders, and the public to participate in this review
process. After the utilities have initially responded to our inquiry, the Commission will convene
a public workshop. Another comment period will follow the workshop.
1 Codified at 16 U.C. ~ 2621.
2 The three regulated utilities are Avista Utilities, Idaho Power Company and PacifiCorp dba Rocky Mountain
Power. Atlanta Power does not meet PURPA's threshold requirement of retail sales of 500 million kilowatt hours in
a calendar year. 16 US.C. ~ 2612(a).
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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: (1) the
conservation of energy supplied by electric utilities; (2) the optimum efficiency of electric utility
facilities and resources; and (3) equitable rates for electric consumers. PURPA ~ 101 16 U.
~ 2611. The 1978 regulatory standards included: (1) cost of service; (2) declining block rates;
(3) time-of-day rates; (4) seasonal rates; (5) interruptible rates; and (6) load management
techniques. 16 U.C. ~ 2621; Order Nos. 17586, 16611. The Energy Policy Act of 1992 added
four more standards: (7) integrated resource planning; (8) conservation and demand-side
management; (9) cost-effective investments in efficient power generation and supply; and (10)
wholesale power purchases, leverage capital structures and adequate fuel supplies. 16 US.C. ~
2621; Order No. 24729, App. A. In response to both PURPA and the 1992 Energy Policy Act
this Commission initiated proceedings to review the federal standards. Order Nos. 17586
16611 24729.
The five new standards address energy efficiency, metering and customer generation.
The Modernization Act generally requires the Commission to begin its review of the five
standards by August 8 , 2006 and decide whether to adopt the standards by August 8, 2007.
C. ~ 2622(b)(4) and (5).3 If the Commission has not completed its review and made its
determination regarding the five standards, then the standards shall be taken up in each regulated
utility s next rate proceeding. 16 U.C. ~ 2622(c).
Although the Modernization Act 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 it is not appropriate to implement any such standard. . ..16 US.C. ~
2621 (a) (emphasis added). The Modernization Act 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-
3 For the net metering, fuel source and fossil fuel efficiency standards, the Commission must complete its review of
these three standards no later than August 8, 2008. 16 US.c. ~ 2622(b)(3)(B). The timeline for consideration of the
Smart Metering standard is ambiguous. Section 1252(a) of the Modernization Act sets February 8, 2007 (I8
months) as the deadline for a decision, while another section sets the deadline at August 8, 2007 (24 months).
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by implementing the standard/comparable standard or has considered the standard but declined
implementation - then no further action is necessary. Id.; 16 U.C. ~ 2621(c)(1).
In undertaking our consideration and determination 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 FIVE FEDERAL STANDARDS
We initiate this inquiry by noting that many of the basic concepts embodied in the
five "new" federal standards are not new to this Commission. The Commission, the three
regulated utilities and other interested parties have previously addressed the efficiency and
energy resource enhancements encompassed in the new standards. Indeed, Congress recognizes
that states may have already considered implementation of the five standards.
The five standards are listed below as set forth in the Modernization Act. After each
standard we include a brief discussion of the standard and set out a list of initial questions for
each utility to answer. The answers to our questions and input from other participants will be the
subject ofthe subsequent public workshop.
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.
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. This net metering tariff applied only to residential and small
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commercial customers with renewable generating facilities of less than 25 kilowatts. 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 file comments regarding this standard. In particular, each
utility should 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.
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?
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.
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
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.
4 On June 19, 2006, A vista 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. 30093 , the Commission
issued a Notice of Modified Procedure seeking comments on Avista s Application no later than July 28 2006.
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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 (A vista). 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. We direct the utilities to comment on whether this standard has already been
implemented by the Commission as part of the IRP process.
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.
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
integrated resource plan (IRP) process.5 We solicit the utilities to 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?
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.
5 For example, the Washington Utilities and Transportation Commission has determined that this standard is
included in Washington s IRP process. Notice of Public Utility Regulatory Policies Act Standards Docket UE-
060649 (June 9, 2006).
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(B) The type of time-based rate schedules that may be offered
under the schedule referred 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 s 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
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.
(D) . . .
(E) . . .
6 Subparagraph (D) addresses PURPA's date of enactment.
7 Subparagraph (E) pertains to third-party marketers of electricity. The Idaho Electric Suppliers Stabilization Act
prohibits third-party marketers. Idaho Code 99 61-332(2) and 61-332(B).
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(F) Notwithstanding subsections (b) and (c) of (16 U.C. ~ 2621),
each State regulatory authority shall, not later than 18 months after
the date of enactment of this paragraph conduct an investigation in
accordance with section (2625(i)) of this title and issue a decision
whether it is appropriate to implement the standards set out in
subparagraphs (A) and (C).
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. In authorizing these Smart Metering programs, the
Commission has 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.s Given this
brief background information, the Commission directs the utilities to address the following
Issues:
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
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?
8 Slide 7 at http://www.ferc.gov/whats-new/headlines/2006/2006-3/07-20-06-demand-response.pdf
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4. Which, if any, of the four listed types oftime-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?
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 are 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.
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 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 US.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.
9 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.org/goto.cfm ?retumto=disp layindustrynews.cfm& industrytop icnbr=3 80&page=http://www.naruc.orglas
sociations/1773/files/dgiaip oct03.pdt
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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.
This interconnection standard may go hand-in-hand with net metering practices or
established procedures for interconnecting qualifying facilities under PURP A. For example
A vista recently filed an Application to amend its Schedule 62 for PURP A qualifying facilities
and adopt a new Schedule 63 for net metering. Both schedules propose to adopt the IEEE 1547
standard for interconnection. See Case No. A VU-06-
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, .( 1MW ? 1MW, or some other limitation)?
4. Should the Commission adopt IEEE Standard 15477
5. Should the Commission adopt the NARUC Model Interconnection
Procedures and Agreement?
6. Are there other issues the Commission should consider regarding this
standard?
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YOU ARE FURTHER NOTIFIED that the Commission has preliminarily
determined that the public interest may not require a formal hearing in this matter and will
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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.
YOU ARE FURTHER NOTIFIED that the utility shall address the questions set out
in the body of this Order by written comment. The utility s written responses to these questions
shall be filed with the Commission within twenty-eight (28) days from the date of this Order.
The utilities' written comments shall contain the case caption and case number shown on the
first page of this Order. Each utility shall also serve interested persons on the Commission
Secretary s service list.
YOU ARE FURTHER NOTIFIED that following receipt of the written comments by
the utilities, the Commission shall convene a public workshop as set out in greater detail below.
DEADLINE TO BE PLACED ON COMMISSION SERVICE LIST
YOU ARE FURTHER NOTIFIED that persons desiring to receive copies of the
utilities' initial written comments must notify the Commission Secretary by letter no later than
fourteen (14) days from the date of this Order. Persons seeking to be served with copies of
the utilities' comments shall provide the Commission Secretary with their postal address and e-
mail address (if available) to facilitate service in this matter. The letter to the Commission
Secretary should also specify to the extent practical whether the interested person requests the
written comments from all utilities or just specific utilities. After the deadline has passed the
Commission Secretary shall issue the service list in this case.
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YOU ARE FURTHER NOTIFIED that the Commission will convene a public
workshop for the purpose of reviewing the utilities ' written comments and to allow other
interested persons to present written/oral comments. The purpose of the workshop is to
determine if there is consensus about: adopting the federal standards; adopting comparable
standards; whether the Commission has already adopted the standard/comparable standard; or
whether the Commission should not implement the federal standards. Following the workshop,
the Commission anticipates that it will issue another Notice seeking written comments. The
public workshop will commence at 9:30 A.M. ON SEPTEMBER 13. 2006 IN THE
COMMISSION'S HEARING ROOM. 472 WEST WASHINGTON STREET. BOISE.
IDAHO [phone]
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YOU ARE FURTHER NOTIFIED that all hearings and prehearing conferences in
this matter will be held in facilities meeting the accessibility requirements of the Americans with
Disabilities Act (ADA). Persons needing the help of a sign language interpreter or other
assistance in order to participate in or to understand testimony and argument at a public hearing
may ask the Commission to provide a sign language interpreter or other assistance at the hearing.
The request for assistance must be received at least five (5) working days before the hearing by
contacting the Commission Secretary at:
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone] (Telephone)
[phone] (FAX)
Mail: secretary(fYpuc.idaho.gov
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission s jurisdiction under the Modernization 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, IDAP A 31.01.01.000 et seq.
ORDER
IT IS HEREBY ORDERED that Avista, Idaho Power and Rocky Mountain Power
file their written comments to the questions set out above and supply all supporting documents
within 28 days of the service date of this Order.
IT IS FURTHER ORDERED that persons interested in being served with the
utilities' comments notify the Commission Secretary by letter no later than 14 days from the
service date of this Order. Persons desiring to be placed on the Commission s service list shall
provide their postal mailing address, electronic mailing address (if available), and indicate
whether they desire to receive comments from just specified utilities or all three utilities.
IT IS FURTHER ORDERED that Avista, Idaho Power and Rocky Mountain Power
serve their comments on the interested persons listed in the Commission s service list.
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DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
;)..g'
-rJ..
day of July 2006.
PAUL JELLAND ,PRESIDENT
&Jv
MARSHA H. SMITH, COMMISSIONER
ATTEST:
J a D. Jewell
mission Secretary
bls/GNR-06-02 dh
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