20060828Avista comments.pdf

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Avista Corp.
1411 East Mission PO Box3727
Spokane, Washington 99220-3727
Telephone [phone]
Toll Free 800-727-9170 RECEIVED
200G AUG 28 AM 9: ~O
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Corp.
August 25, 2006 IDAHO PUBLIC
UTILITIES COMMISSION
Jean Jewell, Secretary
Idaho Public Utilities Commission
Statehouse Mail
W. 472 Washington Street
Boise, Idaho 83720
Re:Avista Comments in Case No. GNR-06-
Dear Ms. Jewell:
A vista Corp hereby submits for filing an original and seven copies of its comments
regarding the Commission s Consideration of the Five Amendments to Section 111 of the
Public Utility Regulatory Policies Act of 1978 (PURPA) Contained in the Energy Policy
Act of 2005 in Case No. GNR-06-02.Avista s comments are responsive to the
questions, italicized below, contained in the Commission s June 29, 2006 Notice of
Inquiry, Notice of Modified Procedure, and Notice of Public Workshop in Order No.
30108.
Net Meterin2
Briefly describe your net metering program.
Net metering is available to all customers of Avista Utilities subject to the terms and
conditions of the Company s Schedule 63, Net Metering Option.As described in
Schedule 63 , to be eligible for the net metering option, a customer-generator must own a
facility for the production of electrical energy that 1) uses as its fuel either solar, wind
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25, 2006
Page 2
biomass or hydropower, or represents fuel cell technology; 2) has a generating capacity of
not more than twenty-five kilowatts; 3) is located on the customer-generator s premises;
operates in parallel with the electric utility s transmission and distribution facilities; and 4)
is intended primarily to offset part or all of the customer-generator s requirements for
electricity.
The Company s Schedule 63 describes the cost to the customer-generator of metering and
interconnection, standards (e., equipment necessary to meet applicable safety, power
quality, and interconnection requirements established by the National Electrical Code
National Electrical Safety Code, the Institute of Electrical and Electronics Engineers, and
Underwriters Laboratories), treatment of balances of generation and usage by the
customer-generator, remaining unused kwh credits, and reversion to previous service.
Are all customers eligible to participate in your net metering program? If 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?
Net metering is available to all eligible customers (as described above) of Avista Utilities
on a first-come, first-served basis until the cumulative generating capacity of net
metering systems equals 1.52 MW which is 0.1 % (one-tenth of one percent) of the
Company s retail peak demand during 1996. The intent of this cap is to allow for a
revisiting of system impacts and rate design in the event that the amount of customer
subscription places burdens on non-participating customers. Under existing net-metering
protocol, the meter "runs backward" from a practical perspective. This means that
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 , 2006
Page 3
customers receIve credit for the total retail rate per kilowatt-hour for net-metered
generation. However, the total retail rate includes a component for distribution and other
costs. That these costs are not recovered from net-metered customers is not problematic
when customer participation is low. The caps in Avista s tariffs provides for review
should customer subscription significantly increase.
State the number of net metering customers by customer class.
A vista is aware of eight net-metered customers on its system: four residential (Schedule
1) customers in Idaho, three residential (Schedule 1) customers in Washington and one
Schedule 11 customer in Washington.
State the amount of net metering generation by customer class.
The total generation of A vista s eight net-metered customers was 51 061 kilowatt-hours
(kwh) in 2005. Of this total , Idaho Schedule 1 is 16 060 kwh; Washington Schedule 1 is
573 kwh; and Washington Schedule 11 is 22 428 kwh.
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?
A vista believes that its current net metering tariff meets the federal net metering standard.
Fuel Sources
Avista concurs with the Commission s statement at page 5 of Order No. 30108, that the
the Fuel Source standard has already been implemented by the Commission as part of the
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25, 2006
Page 4
IRP process. A vista s Integrated Resource Plan (IRP) describes the Company s plan for
resource diversity including renewable technologies. The Company s 2005 IRP shows
that its 2016 preferred resource strategy includes the addition of DSM (69 MW), wind
(400 MW), biomass (80 MW), plant upgrades (52 MW), and coal (250 MW). The IPUC
IRP process assures that resource diversity is and will be considered pursuant to EP ACT
2005.
Fossil Fuel Generation Efficiency
At page 5 of Order No. 30108 , the Commission states: "Increasing the efficiency of
existing generating resources may already be a part of the integrated resource planning
process (IRP)." Avista concurs with this statement and notes the Company s current IRP
specifically analyzes hydro efficiency upgrades. Thermal efficiency improvements are
reviewed on an ongoing basis. For example, the Colstrip owners committee has reviewed
and implemented improvements subject to cost-effectiveness and agreement from all
owners. Other company-owned thermal facilities, by their nature, may not have much
potential for technological or cost-effective improvements. Coyote Springs 2 is a new
plant and employs contemporary technology.The Company peaking facilities
(Rathdrum, Boulder, etc.generally do not have potential for cost-effective
improvements. The potential for modifying a peaking facility (re Rathdrum) into a
combined cycle combustion turbine has been reviewed in past IRPs and remains on the
table as an option, again subject to cost-effectiveness.Companies ' IRPs are the
appropriate place to analyze fossil fuel generation efficiency and A vista believes that the
Commission is currently in compliance with this standard.
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 2006
Page 5
"Smart Meterin2
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?
A vista is currently in year two of a four year plan to deploy Advanced Meter Reading
(AMR) in our Idaho service territory as proposed in the Company s 2004 general rate
case (Case Nos. A VU-04-01 and A VU-04-01). In 2005 , Avista deployed over
112 000 gas and electric meters with AMR capability in the urban areas of Sandpoint
Post Falls, Coeur d'Alene, and Lewiston. Of these 112 000 meters, approximately 59 000
were electric meters and 53 000 were gas meters. The equipment installed in 2005 was
Itron s ERT radio frequency technology. As deployment progressed, these meters were
moved from on-the-ground meter reading to drive-by routes to collect the monthly
reading used for billing. The majority of the meters deployed were for residential
customers. The development of the technology for commercial (three phase) electric and
some commercial gas meters has become available in 2006 and deployment is proceeding
for commercial customers in these areas as shipments arrive.
In 2006, A vista began its deployment of DCSI's TW ACS system based on Power Line
Carrier (PLC) technology in the more rural areas of Oldtown, Priest River, Clark Fork
Grangeville, Orofino, and areas surrounding these communities. Approximately 22 000
Itron meters with the TW ACS PLC module will be installed in 2006. This will include
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25, 2006
Page 6
both residential and commercial electric customers. Further, in 2006 the first deployment
of Itron s Fixed Network in Sandpoint began. Both the TW ACS and Fixed Network
systems will be providing monthly billing reads. However, both systems are capable of
collecting interval data that would allow the system to be Time-of-Use (TOU) capable as
was indicated with A vista s filing to the IPUC.
A vista will continue its AMR deployment in Idaho in 2007 and 2008 to complete the
remaining areas of its Idaho service territory.This deployment will include the
outstanding commercial meters, the remaining areas for Itron ERT deployment, the
remaining areas for TW ACS deployment, and the Fixed Network in areas where Itron
ERTs have already been installed. This equates to approximately 50 000 meters yet to
receive AMR meters in Idaho.
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?
The Commission should not require by rule that, by February 8, 2007 , each utility to offer
a time-based rate to each customer class and the necessary time-based metering to
individual customers upon request.Two components of such a requirement are
problematic for A vista. First, it would be difficult to finish installation of time-based
metering and associated data storage and billing system upgrades by February 8, 2007.
Second, the time-based metering "upon request" option by customers would only be
feasible if the Company had in place time-of-use tariffs.This would necessitate
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 2006
Page 7
appropriate associated data storage and billing system updates as discussed below.
offered in a rate tariff, TOU could be by individual election, but from the utility
perspective this is an "all or nothing" proposition.
Recent and past analyses ofTOU by Avista show it is likely not cost-effective for Avista
to implement TOU rates for all customer classes. The potential savings created by
customers shifting their daytime demand into the night does not outweigh the cost of
meter installation, software upgrades, and associated operational costs. TOU, however
could be cost-effective for our large industrial customers. These customers consume
large quantities of power and already have sophisticated TOU-ready meters, making them
potentially "low-hanging fruit."
A high-level study recently performed by Avista shows the value of Avista s on-peak/off-
peak differential, combined with avoided capacity charges, to be under 1.5 cents per
kilowatt hour. This value needs to be compared to the cost of metering, software, and
operating costs for TOU implementation in our residential and small commercial
customer classes, which represent over 50% of our customer usage. The Company
preliminary cost estimate for associated data storage and billing system updates is $22
million. We would expect that with a 1.5-cent cost differential this would not be cost-
effecti ve.As mentioned earlier, however, there may be an opportunity for large
industrial customers to provide load reduction through TOU programs with significantly
less cost than through a total Company approach. The Company is examining this as part
of its 2007 Integrated Resource Plan.
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 2006
Page 8
3. Should the Commission adopt the time-based metering and communications
standard by applying the same requirements to all utilities?
The Commission should examine and determine whether to adopt time-based metering
and communication on a generic basis for the policy and principles underlying the
consideration of TOU adoption. However, the Commission should consider the specific
application of implementation ofTOU in separate proceedings
For the overall policy aspects in considering TOU adoption, issues common to all
stakeholders will likely be discussed.Participation and perspectives of each utility
should help inform others. Yet, there will likely be issues unique to each utility for
implementation.The details for implementation may involve different metering
equipment and architectural design of data collection. The power supply cost profiles
(e., the value of on-peak versus off-peak costs) may also be different.If the
Commission adopts TOU pricing, the same type of rate schedule should not be required
of all utilities and for all rate classes.
4. Which, if any, of the four listed types of time-based rate schedules should the
Commission require? Should the same types of rate schedule be required of all
utilities and for all rate classes?
If the Commission adopts a time-based metering and communications standard, of the
four listed types of time-based rate schedules, A vista suggests that only time of use
pricing be required, based on cost-effectiveness. The second and third categories, critical
peak pricing and real-time pricing, respectively, should be considered at a later time
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25, 2006
Page 9
based, in part, on customer response to time of use pricing, if implemented. The fourth
category, credits for consumers with large loads who enter into pre-established peak load
reduction agreements, has been implemented by A vista on several occasions. In late
2000, the Company instituted a large-customer buy-back program. More recently, on
July 24 , 2006 , Avista implemented bi-Iateral agreements with three customers at a time
of near-record temperatures.
5. Are there other issues the Commission should consider in reviewing this
standard?
Yes. The Company notes that time-of-use metering and pricing has been considered by
utilities periodically. A vista reviews the cost-effectiveness of TOU on an ongoing basis.
This is also included in its IRP analyses.
Interconnection
1. Should the Commission adopt this standard for interconnecting a customer s on-
site generating facility to local distribution facilities?
Yes, A vista recommends adopting the interconnection standard for customers with on-
site generating facilities pursuant to Section l254(a) of the National Energy Policy Act of
2005.
2. Do the utilities currently have tariffs, agreements, procedures or schedules
delineating interconnection standards of customer-owned generating facilities?
yes, where are they located (e.g., 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?
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 , 2006
Page 10
A vista currently has in place a tariff (Schedule 70, Part 28) that states the general
conditions and requirements and technical specifications for the safe and reliable
operation of interconnected customer-owned generating facilities.The per-customer
capacity of customer-owned generation facilities for interconnection is limited to 25 kW
or less in capacity. However, the Company contemplates increasing this capacity based
on the outcome of this Inquiry and a similar case before the Washington Utilities and
Transportation Commission as discussed below.
3. Should the Commission adopt or consider separate interconnection standards for
smaller and larger generating facilities (e.g., ~25 kW up to 100 kW, ~1MW,
)-1 MW, or some other limitation)?
A vista recommends that interconnection standards be adopted, at the state level , for
projects ~300 kW. The Company supports this level for interconnection standards based
on a series of technical workshops over the past the year with Washington-load serving
entities to collaboratively develop a consistent set of standards.Avista filed joint
comments with Puget Sound Energy and several public utilities in the WUTC's similar
inquiry stating that the following guidelines should govern interconnection of facilities
greater than 300 kW:
1. All interconnection customers shall be treated in a non-discriminatory and
non-preferential manner.
2. The utility shall review all interconnection to maintain safe, adequate and
reliable electric service to its retail electric customers.
3. The utility shall evaluate the cumulative effect on circuits and load pockets.
Joint Comments of the Washington Load-serving Utilities, Washington Utilities and
Transportation Commission, Docket No. UE-060649, Re: Public Utility Regulatory Policies Act Standards
August 11 , 2006
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25 , 2006
Page 11
4. Interconnection customers shall bear the costs of interconnection, operation
and maintenance.
5. Interconnection service does not include retail electric or other services.
6. The electric utility shall establish, and amend as necessary to maintain the safe
and reliable operation of its system, operating, system design, and
maintenance requirements.
7. Any requirements should not restrict utilities from developing timelines that
allow the utility and interconnection customer to engage in discussions
regarding study results and design options.
8. Technical requirements for all interconnections shall comply with applicable
IEEE, NESC, NEC and other safety and reliability standards.
Given the complexity of interconnecting generation in excess of 300 kW to utility
distribution systems, the A vista recommends that each utility develop standards that take
into account each utility s unique circumstances. These interconnection standards are
intended to insure the safe and reliable operation of the distribution system.
4. Should the Commission adopt the IEEE Standard 1547?
Yes, A vista recommends that the Commission adopt the IEEE Standard 1547.
5. Should the Commission adopt the NARUC Model Interconnection Procedures and
Agreement?
Avista recommends that the Commission adopt the NARUC Model Interconnection
Procedures and Agreement (Procedures) as a guideline. The Company notes that there
are requirements that, if made mandatory, may be difficult to implement. For example
the Procedures state:
Subject to any State regulatory authority rule for routine maintenance and repairs on
Interconnection Provider s system, the Interconnection Provider shall provide the
Interconnection Customer with seven days' notice of service interruption.
Avista Comments re PURPA Standards, Case No. GNR-06-
August 25, 2006
Page 12
This may be difficult to accomplish because jobs are assigned the same day and, under
current procedures, are not necessarily scheduled a week in advance.
The Company would like to emphasize that it supports the spirit of the Procedures and is
not opposed to its adoption in principle.Should the Commission adopt the Model
Interconnection Procedures in entirety, A vista will adjust its operations accordingly.
6. Are there other issues the Commission should consider regarding this standard?
, there are no other issues the Company suggests for consideration by the Commission
regarding this standard.
Thank you for the opportunity to comment on this inquiry. Please direct any questions on
this matter to Bruce Folsom at [phone].
Sincerely,
AI
"""
Kelly Norwood
Vice-President, State and Federal Regulation
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have served, via electronic mail, Avista Corporation
comments regarding the Commission s Consideration of the Five Amendments to Section
111 of the Public Utility Regulatory Policies Act of 1978 (PURPA) Contained in the
Energy Policy Act of200S in Case No. GNR-06-02 to the following:
COMMISSION:Jean D Jewell, Secretary
Idaho Public Utilities Commission
Statehouse
Boise, ID 83720-S983
Email: iean.iewell~puc.idaho.gov
AVISTA CORPORATION:Kelly Norwood
Vice President State Regulation
Bruce Folsom, Manager
A vista Utilities
PO Box 3727
Spokane, W A 99220-3727
Email: kelly.norwood~avistacorp.com
bruce. fo lsom~a vistacorp. com
David Meyer
P. & Chief Counsel
A vista Corporation
PO Box 3727
Spokane, W A 99220-3727
Email: david.meyer~avistacorp.com
IDAHO POWER COMPANY:Barton L. Kline, Senior Attorney
Monica B. Moen, Attorney
Lisa Nordstrom, Attorney
Idaho Power Company
PO Box 70
Boise, ID 83707-0070
Email: bkline~idahopower.com
mmoen~idahopower.com
lnordstrom~idahopower. com
John R. Gale, VP- Regulatory Affairs
Maggie Brilz, Director, Pricing
Greg Said, Manager, Revenue Requirement
Idaho Power Company
PO Box 70
Boise, ID 83707-0070
Email: rgale~idahopower.com
mbrilz~idahopower. com
gsaid~idahopower.com
PACIFICORP, dba ROCKY
MOUNT AIN POWER:
Dean Brockbank, Attorney
PacifiCorp/ dba Rocky Mountian Power
201 S. Main St., Suite 2200
Salt Lake City, UT 84111
Email: dean.brockbank~pacificorp.com
Brian Dickman, Manager
PacifiCorp/ dba Rocky Mountian Power
201 S. Main St., Suite 2300
Salt Lake City, UT 84111
Email: brian.dickman~pacificorp.com
COMMISSION STAFF:Donald L. Howell, II
Deputy Attorney General
Idaho Public Utilities
Commission
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
Email: don.howell~puc.idaho.gov
Harry Hall, Staff Engineer
Idaho Public Utilities
Commission
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
Email: harry.hall~puc.idaho.gov
SORENSON ENGINEERING:Ted S. Sorenson, P .
Sorenson Engineering
5203 South 11 th East
Idaho Falls, ID 83404
Email: ted~tsorenson.net
PAM CONLEY:Pam Conley
PO Box 2526
Boise, ID 83701
Email: pgconley~cableone.net
HUNT TECHNOLOGIES:Scott H. DeBroff, Esq.
Smigel, Anderson & Sacks
4431 N. Front Street
Harrisburg, PA l 711 0
Email: sdebroff~sasllp.com
NW ENERGY COALITION:Ken Miller
Idaho Energy Advocate
NW Energy Coalition
5400 W. Franklin, Suite G
Boise, ID 83705
Email: ken~nwenergy.org
J. R. SIMPLOT COMPANY:David Hawk
Director, Energy Natural Resources
J .R. Simplot Company
PO Box 27 (83707)
999 Main Street
Boise, ID 83702
Email: dhawk~simplot.com
ITRON, INC:Ben Boyd
Director, Regulatory Affairs
Itron, Inc.
5430 Hickory Village Dr.
Kingwood, TX 77345
Email: ben.boyd~itron.com
INDUSTRIAL CUSTOMERS
OF IDAHO POWER:
Peter Richardson
Richardson & O'Leary PLLC
515 N. 2ih Street
Boise, ID 83702
Email: peter~richardsonandolearv.com
Dated at Spokane, Washington this 25th day of August 2006.
Patty Olsn
Rates Coordinator