20060925_1680.pdf

DECISION MEMORANDUM
TO:COMMISSIONER KJELLANDER
COMMISSIONER SMITH
COMMISSIONER HANSEN
COMMISSION SECRETARY
COMMISSION STAFF
FROM:DON HOWELL
DATE:SEPTEMBER 20, 2006
SUBJECT:THE COMMISSION'S REVIEW OF THE FIVE NEW PURPA
ST ANDARDS CONTAINED IN THE ENERGY POLICY ACT OF 2005,
CASE NO. GNR-06-
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. The five new PURPA
standards are: net metering; fuel source diversity; fossil fuel generation efficiency; time-based
metering and communications ("Smart Metering ); and interconnection services to customers
with on-sight generating facilities. Order No. 30108. The Commission directed that the three
large electric utilities (A vista, Idaho Power and Rocky Mountain Power) initially respond to
several questions set out in the Commission s Notice. The Notice required that the utilities serve
their comments on a service list of interested persons. The three utilities filed their written
comments on August 2006.
The Notice also scheduled a public workshop for September 13, 2006. The purpose
of the workshop was to review the utilities' responses to the questions set out in the
Commission s Notice. In addition, the Commission sought to determine whether there was
consensus about adopting the five federal standards, adopting comparable standards, whether the
Commission had already adopted the standards, or whether the Commission should not
implement the federal standards. The following parties attended and participated in the public
workshop: Avista, Idaho Power, Rocky Mountain Power, Hunt Technologies, the Industrial
Customers of Idaho Power, Distribution Control Systems, John Weber, Jay Blackhurst, and the
Commission Staff.
DECISION MEMORANDUM
THE FIVE 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. Utilities ' Responses . At the public workshop, Staff summarized the comments
provided by each utility. 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 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 customer, 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 is proposing to change the net credit for net metering generation to 85% of the
avoided cost contained in Schedule 84. Comments are due October 2006.
2. Workshop Comments. The utilities and the participants generally agreed that the
utilities' net metering programs meet the federal net metering standard set out above. 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. The participant was encouraged to file
comments in Idaho Power s pending case.
DECISION MEMORANDUM
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. 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 Integrated
Resource Plan (IRP) process. In their comments, 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.
2. 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. Utilities ' Responses . In Order No. 30108 the Commission also asked whether
increasing fuel efficiency is already part ofthe utility IRP process. Order No. 30108 at 5. All of
the utilities responded in the affirmative that fossil fuel efficiency is a part of their IRPs. For
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 all indicated that the
Commission need not take further action on this standard because it has already been
implemented.
Workshop Comments The participants did not disagree with the utility'
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.
DECISION MEMORANDUM
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 in subparagraph (A) include, among
others -
(i) time-of-use pricing. . .
(ii) critical peak pricing. . .
(iii) real-time pricing. . .; 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. 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" program and have partially implemented the standards.
In particular, A vista 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 2007.1 Avista
recommended that the Commission not adopt this standard for several reasons. First, A vista
I 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 ofthe 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.
DECISION MEMORANDUM
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 currently offers optional time-of-day 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 that it was neither achievable nor reasonable to adopt
this standard by February 2007. Rocky Mountain did agree with the Commission 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 cost of
deployment are commensurate with the benefits. The Company reported that 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 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.
2. 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. If
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:
DECISION MEMORANDUM
(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.
1. Utilities' Responses. The utilities indicated that for the most part they have
already implemented this federal standard. A vista indicated 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 of IEEE Standard 1547. In response to the question
about whether the Commission should adopt the NARUC Model Interconnection Procedures and
Agreement (the "Model"), the Company suggested that 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 indicated it did not need to adopt IEEE Standard 1547 because the
Company already uses the standard and 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 k W and larger generators may need additional protections. Rocky
Mountain also recommended that 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 PacifiCorp.
Idaho Power indicates that it is in compliance with the federal interconnection
standard except it has not explicitly adopted IEEE Standard 1547. However, it intends to due so
DECISION MEMORANDUM
this month. Idaho Power s interconnection policies and practices are contained in its Schedules
72 and 84; in its Best Practices (website); and in its OATT. 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 that the IEEE standard is not applicable to all situations because it applies to facilities
of 10 MV A or less. Turning to the NARUC Model, Idaho Power supports 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.
2. Workshop Comments. The participants did not voice any disagreement with the
utilities' comments.
STAFF RECOMMENDATION
In the Commission s initial Notice oflnquiry, it indicated that it would seek another
round of comments after the public workshop. Given the general consensus on four out of the
five standards, Staff believes that a 21-day comment period would be sufficient. This will allow
the non-utility participants, Staff and the public to comment upon the five federal standards.
COMMISSION DECISION
Does the Commission wish to issue another Notice of Modified Procedure inviting
comments from the non-utility workshop participants, and other interested persons regarding the
five federal standards?
Does the Commission wish to set a 21-day comment period?
Does the Commission wish to set a 14-day reply comment for the utilities?
))~
Don Howell
bls!M:GNR-O6-
DECISION MEMORANDUM