20080403Paulson Direct.pdf

r'~"t t:ivr:o,-.1 '.i i.DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL,
GOVERNNTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727TELEPHONE: [phone]FACSIMILE: [phone]
REGULAT~;~t) 3 pi' f
AUJ ¡U'n - . ii¡ .: 08
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC AN
NATUR GAS SERVICE TO ELECTRIC
AN NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
CASE NO. AVU-G-08-01
DIRECT TESTIMONY
OF
GREG A. PAULSON
FOR AVISTA CORPORATION
(ELECTRIC AN NATURA GAS)
1
2
I. INTRODUCTION
Q.Please state your name, employer and business
3 address.
4 A.My name is Greg A. Paulson and I am employed as
5 the Manager of Customer Service, Analytics and Technology,
6 for Avista Utilities, at 1411 East Mission Avenue, Spokane,
7 Washington.
8 Q.Would you describe your educational background
9 and professional experience?
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A.I am a 1991 graduate of Montana State University
wi th a degree in Mechanical Engineering.I completed
Washington State University's Project Management
13 Certificate program in 2007. I joined the Company in 2004.
14 In the past 4 years I have performed duties as a Metering
15 Automation Engineer and proj ect manager for the Company's
16 Idaho Advanced Meter Reading (AM) proj ect.I have
17 recently accepted the position of Manager of Customer
18 Service.
19 Q.What is the scope of your testimony in this
20 proceeding?
21 A.My testimony will describe implementation of AM
22 for Avista' s customers in the State of Idaho. The Company
23 requests recovery of capital expenditures related to the
24 deploYment of AM in idaho. Per Commission Order No. 30229,
25 I will address the status of the current AM program, cost
Paulson, Di 1
Avista Corporation
1 recovery proposal, time of use capability and demand
2 response.
3 Q.Are you sponsoring any exhibi ts in this
4 proceeding?
5 A.Yes. I am sponsoring Exhibit No. 12, Schedules 1
6 and 2, which were prepared under my direction.
7 Q.Please provide a list of acronyms/definitions
8 that pertain to the verbiage contained within this
9 testimony.
10 A.The following is a list of acronYms and their
11 definitions contained within this testimony:
12 AM - Advanced Meter Reading - The components13 necessary to read a meter remotely using technology
14 to retrieve meter-reading data through a handheld15 device, a mobile collection system, or a one-way
16 communication network.
1718 AMI - Advanced Metering Infrastructure19 Industry terminology to better reflect the
20 transition from AM to systems with expanded
21 capabili ties of two-way communication networks.
22 AMI systems measure, collect, and analyze energy
23 usage information from advanced metering devices
24 through various communication media. The25 infrastructure includes hardware, software,
26 communications equipment, customer associated
27 systems and data management software.
2829 Mobile Collection System - Mobile Wireless Unit30 used to collect consumption readings from electric31 and natural gas meters.
32
33 Manual Meter-Reading System - The software package34 and handheld equipment that facilitates a manual35 meter reading process. This consists of the36 handheld devices that are used to collect the37 existing meter-reading data and the software to
38 feed the information to the Customer Service39 System.
Paulson, Di 2
Avista Corporation
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PLC - Power-Line-Carrier - A system by which
communications are transmitted and received over
distribution level power lines.
Radio-Based Technology A
communications are transmitted
radio frequencies.
sys tem by whichand received via
TWACS'l - Two-Way Automated Communication System -
The AMR system Avista installed in lower electric
meter density areas of our service territory. Thesystem uses power-line-carrier technology to
communicate with the meter.
II. BACKGROUN
Q.What was the Company's proposal for AM in its
18 last general rate proceeding?
19 A.In 2004, in the Company's last general rate case
20 filed with the Idaho Public Utilities Commission (IPUC),
21 Case Nos. AVU-E-04-01 and AVU-G-04-01, the Company proposed
22 to install AMR devices on all Idaho electric and natural
23 gas meters over a four-year period commencing January 2005.
24 The project included the installation of additional
25 electronics for existing meters as well as other
26 communication infrastructure, and finally computer hardware
27 and software investment.
28 Due primarily to the multi-year nature of this
29 project, the Company proposed to treat the AM investment
30 costs in the following manner:All capital investment
31 would follow Avista' s standard capitalization policy and
32 would be capitalized to a regulatory asset, FERC account
Paulson, Di 3
Avista Corporation
1 182, and remain there until the entire AM proj ect became
2 operational, or used and useful.At completion, the
3 proj ect would be placed into the appropriate FERC plant
4 accounts, depreciation would begin and the investment would
5 receive appropriate rate base treatment in regulatory
6 filings.
7 In the I PUC 's Order No. 29602, in Case Nos. AVU-E-04-
8 01 and AVU-G-04-01, dated October 8, 2004, at page 51, the
9 Commission supported the Company's plans to install AM and
10 authorized the Company- reques ted deferral accounting
11 treatment requested by the Company for its related
12 investment.
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III. PROJECT SUMY
Q.What is the current status of the Company's AM
16 in Idaho?
17 A.In 2005, the Company began a four-year project to
18 convert all natural gas and electric meters to AMR in the
19 State of Idaho. As of this filing, nearly 180,000 natural
20 gas and electric meters have been automated. Over 139,000
21 natural gas and electric meters were automated using radio-
22 based technology and 40,000 were automated utilizing power
23 line carrier (PLC) technology.Currently, approximately
24 27,000 electric and natural gas meters utilizing radio-
25 based technology are read automatically by a radio-based
Paulson, Di 4
Avista Corporation
1 network and 112,000 are read through a mobile collection
2 system.Of the 112,000 meters that are being read on the
3 mobile collection system, all electric and the majority of
4 the natural gas meters will be converted to a radio-based
5 network in 2008.There are a small numer of natural gas
6 meters that reside in areas where Avista does not have
7 electric service or reside in the PLC areas that will
8 continue to be read by the mobile collection system.
9 Electric meters on the PLC system are read automatically,
10 and do not require a meter reader or mobile unit to collect
11 the meter reading. Exhibit No. 12, Schedule 1 is a map of
12 the Company's Idaho AM installations.
13 Q.Please explain how the mobile collection system
14 works.
15 A.The mobile collection system works by having a
16 meter reader drive an automobile equipped with a wireless
17 mobile collection system that gathers consumption data from
18 radio-based meters. A mobile collection system can gather
19 up to 10,000 reads per day in dense areas.In contrast,
20 tradi tional meter reading would typically read between 500
21 - 700 meters per day in this same area.Al though the
22 mobile collection system does not provide interval data, it
23 does offer the benefits of increased operational
24 efficiencies and enhanced employee safety.
Paulson, Di 5
Avista Corporation
1 Q.Please describe the Company's meter deployment of
2 AM in Idaho.
3 A.Prior to beginning the deploYment of the Idaho
4 AM proj ect the Company solicited a competi ti ve bid for
5 contract installations of electric and gas meters.Tru-
6 Check was the successful bidder, and had previously been
7 awarded the installation contract for an AM project that
8 the Company conducted in its Oregon service territory.
9 Tru-Check was responsible for installation of more than 95%
10 of the meters associated with the project.Meters with
11 special requirements such as commercial and three phase
12 meters were handled by the Company.Tru -Check provided
13 onsite project managers and hired installers from the local
14 areas.Installers were put through extensive training and
15 then were evaluated through Tru-Check i s quality assurance
16 plan.Tru-Check provided a service to handle any claims
17 made by customers during the installation process. To date
18 only one commission complaint was received associated with
19 the proj ect that installed over 180,000 meters.
20 Q.How did you communicate the meter change with
21 customers?
22 A.A comprehensive communication plan was developed
23 internally and shared with the IPUC Staff for review prior
24 to implementation.
Paulson, Di 6
Avista Corporation
1 Q.Please sumrize the Company's perspective on AM
2 and AMI.
As the Company has progressed with its four-year
4 deploYment of AM in our Idaho service terri tory, there
3 A.
5 have been many advances in the AM industry, as well as
6 increased interest in Advanced Metering Infrastructure
7 (AMI) 1 from utili ties across the nation.Many large
8 utili ties across the nation are deploying pilot AMI systems
9 and working on proposals for large scale deploYment of AMI
10 systems.There are a numer of utilities that are still
11 focused on deploYment of AM systems because of the value
12 proposition represented by AMR systems.AMI sys tems tend
13 to be more capital intensive and the corresponding benefits
14 of these systems are continuing to develop.In conjunction
15 with the focus on AMI systems, the functionality of AM
16 systems continue to be enhanced and offer additional
17 functionality. An example is the progression from a drive-
18 by reading system to a network system that provides the
1 Definiton of Advanced Metering Infrastructure (as defined by Utiity AMI group)
An advanced meterig inastrctue is a comprehensive, integrated collection of devices, networks,
computer systems, protocols and organzational processes dedicated to distrbutig highy accurate
informtion about customer electrcity and / or gas usage thoughout the power utiity and back to the
customers themselves. Such an infrastrctue is considered "advanced" because it not only gathers
customer data automatically but does so securely, reliably, and in a tiely fashion while adherig to
published, open stadards and permttg simple, automated upgrading and expanion. A well-deployed
advanced meterig inastrctue enables a varety of utility applications to be performed more accurately
and effciently includig tie-differentiated taffs, demand response, outage detection, theft detection,
network optimation, and maket operations.
Paulson, Di 7
Avista Corporation
1 means to read the meters more frequently than once per
2 month.
3 Q.What technology or type of AM devices did the
4 Company install for its electric meter system?
5 A.The Company utilized a combination of AMR
6 technologies in its Idaho service terri tory commonly known
7 as a "hybrid" AM system.We installed radio-based
8 technology in areas with higher meter densities, and a PLC
9 based technology in areas with lower densities.We
10 continue to use telephone-based technologies for selected
industrial accounts.A numer of factors determined where11
12 each technology was utilized including geography,
13 distribution configuration, installation costs and the
14 presence of natural gas.All electric meter technologies
15 have the capability to provide hourly or more frequent
interval data.Meters utilizing a radio-based technology16
17 were initially read monthly through a mobile device.In
18 selected areas (Sandpoint and Moscow) we have installed a
19 fixed radio communication network to fully evaluate the
20 network technology and the future uses of the interval data
21 available from the system.The Company will continue the
22 deploYment of this fixed radio communication network in the
23 remaining areas of Idaho currently being read by the mobile
24 collection system in 2008 with the exception of a small
25 numer of natural gas meters as mentioned previously. The
Paulson, Di 8
Avista Corporation
1 PLC electric meters that were installed are also capable of
2 providing interval data and are also being evaluated for
3 future uses of the interval data.
4 Q.What technology or type of AM devices did the
5 Company install for its natural gas meter system?
6 A.The Company installed radio-based technology on
7 all natural gas meters and they are being read monthly by a
8 mobile device.Since natural gas meter installations are
9 inherently different than electric meter installations,
10 some options available for electric meters were not
11 economically viable or applicable for natural gas meters.
12 This is particularly true in rural areas where it would
13 require the deploYment of two separate technologies.By
14 installing radio-based endpoints and reading the meters by
15 a mobile device, the identified savings in meter reading
16 expenses can be realized.Where practical, natural gas
17 meters will be read by the fixed radio communication
18 network.
19 Q.What other AM systems did the Company review
20 prior to selecting the deployed technology?
21 A.Prior to the initiation of the Idaho AM project,
22 Avista had evaluated several advanced metering systems.
23 Avista had installed over 74,000 radio and 350 PLC based
24 AM devices throughout Washington, Oregon and California
25 including 1,700 within the State of Idaho.Our supplier
Paulson, Di 9
Avista Corporation
1 for radio-based equipment had been Itron, based in Liberty
2 Lake, washington.We had utilized Hunt Technologies for
3 PLC based technology.
4 Due to the past performance of the Itron radio-based
5 equipment and the ability of their systems to be deployed
6 in a drive-by environment that could later be converted to
7 a fixed radio-based network, their equipment was selected
8 for the higher meter density areas of our service
9 territory.For the lower meter density areas of our
10 service territory we evaluated PLC technology and selected
11 Aclara' s TWACS'l system.
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iv. AM FUCTIONS AN BENEFITS
Q.Describe the benefits that were realized by the
15 Company and its customers due to the implementation of AM.
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A.From 1995 to 2003, meter reading expenses in
Idaho increased an average of 4.8% each year.In addition
18 to direct meter reading savings compared to manual meter
19 reading, this technology provides the foundation for later
20 adoption of retail electric energy pricing that may vary by
21 hour of the day or day of the week.This type of pricing
22 can ultimately be used to provide customers economic
23 incentives to curtail usage during critical energy periods.
24 The electric meter equipment Avista installed will provide
25 interval metering data, as well as indications of tampering
Paulson, Di 10
Avista Corporation
1 and information on outage conditions.These additional
2 functionali ties of the system are continually being
3 evaluated in an effort to determine how best to integrate
4 into our existing business systems.An example is the
5 ongoing development of a means to integrate the PLC system
6 meters into our existing outage management system in an
7 effort to improve our outage and restoration processes.
8 This equipment is not intended to provide aggregated
9 demands for tariff calculations ¡however, it will enhance
10 Avista' s ability to provide consolidated billing statements
11 for customers with multiple accounts.
12 AM helps eliminate the need for estimated reads,
13 reduces the volume of phone calls associated with estimated
14 reads and the need for investigations related to such
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calls.Customer billing will be more accurate because
estimates and misreads will be reduced.The actual
17 metering accuracy will not be affected by this automated
18 system and will continue to be monitored through our
19 periodic sampling program.
20 Additionally, information obtained through a networked
21 AM system will be of value in determining more efficient
22 specifications for distribution equipment used to serve
23 Avista' s customers.
24 A networked AM system could also provide information
25 to help manage operations during outages and may prevent
Paulson, Di 11
Avista Corporation
1 extended customer outages. Additional software (which has
2 not been installed, but can be added later) could allow
3 customers on-line access to hourly load profile data, which
4 would allow them the opportunity to better manage their
5 electric consumption.Since all residential electric
6 meters have been updated with new solid state meters,
7 customers will now be able to easily read kWh consumption
8 values directly from the meter's liquid crystal display
9 (LCD) readout.
10 Q.What other advantages are associated with AM
11 technology?
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A.Deploying AM technology could provide
opportunity for operational savings by reducing or
14 eliminating both regular and after-hours service calls due
15 to reconnecting or disconnecting service at the meter.In
16 the case of an after-hours reconnect, the service can be
17 remotely activated within minutes as opposed to hours in
18 the more remote areas, thus providing faster response to
19 customers and eliminating the need to send a service person
20 to the premise on overtime.
21 Increased employee safety is also an advantage.
22 Dangerous pets, treacherous driving conditions, obstructed
23 and unsafe meter access and potentially confrontational
24 customer contacts can be greatly reduced by utilizing this
25 technology .
Paulson, Di 12
Avista Corporation
1 Q.Does this system provide the capability for
2 future Time-of-Use or critical peak pricing?
3 A.Yes.As described above,this technology
4 provides the capability for the remote capture of electric
5 interval meter readings in intervals of one hour or less.
6 The significance of capturing interval readings is that it
7 provides the foundation for later adoption of retail energy
8 pricing that may vary by hour of the day or day of the
9 week.This type of pricing can ultimately be used to
10 provide economic incentives to customers to curtail usage
11 during critical energy periods.
12 Al though this proj ect scope did not include the
13 necessary modifications to our billing system to implement
14 a time of use or critical peak rate structure, the meters
15 that have been installed are capable of providing the field
16 data necessary to support this type of system in the
17 future.
18 Q.Does AM technology allow the Company to evaluate
19 Demnd Response programs?
20 A.Yes. Data gathered from the AM technology
21 deployed will allow evaluation of the Company's Demand
22 Response programs. The Company's approved tariff Schedule
23 96 "Energy Load Management Programs pilot" offers
24 residential and commercial demand response programs in
25 portions of Sandpoint and Moscow for a two-year period.
Paulson, Di 13
Avista Corporation
1 Internet protocol thermostats, direct control units and
2 related technology are being installed to reduce energy
3 usage at peak times of the year and to allow the Company to
4 gain experience with customer acceptance, program design,
5 operational components, and cost-effectiveness.
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v. COSTS
Q.What was the cost to install this system in
9 Idaho?
10 A.The total capital expenditures to install this
11 system in Idaho are projected to be $28.8 million by the
12 completion of full system deploYment at the end of 2008.
13 Please refer to Table 1 below that provides a breakdown of
14 the costs associated with the AM system deploYment on a
15 yearly basis.
16 Table 1
2005 2006 2007 2008 Tota/**
Total Meters 112,144 23,627 43,996 Balance*
Cost $6,914,502 $5,930,636 $5,028,807 $3,OQ7,370 $20,881,315
Allocation of Fixed
CompanyO/H
AFUDC
$1,273,844 $689,056 $511,433 $300.737 $2,775,070
$221,447 $1,041,305 $1,772,994 $2,070,068 $5,105,814
Idaho Capital
Expenditures
$8.409,793 $7.660.997 $7 313.234 $5.378.175 $28:762.199
*Remaining Fixed Network Installations and Remaining Commercial
Meters
**Total amount represents costs through 2008. The Company anticipates an additional cost in 2009
to optimize the system.
Paulson, Di 14
Avista Corporation
1 Q.Does the Company expect to incur additional costs
2 in 2009 and how will they be accounted for?
3 A.The Company plans to deploy the remaining
4 infrastructure for the fixed radio communication network in
5 2008.Based on the technology that was available in the
6 early deploYment of the project it is anticipated that
7 there will be network optimization2 activities to insure
8 that the system is reading all meters.Due to the
9 iterative nature of deploying the infrastructure, it is
10 anticipated that there will be additional costs incurred in
11 2009 to optimize the system.These costs will be
12 capi talized to plant in service as they become used and
13 useful and will be accounted for and recovery sought in
14 future rates.
15 Q.How do the current costs of the AM system
16 compare to the estimates developed in 2003?
17 A.Exhibit 12, Schedule 2 provides a reconciliation
18 of the estimated cost of $28.8 million to the preliminary
19 cost estimate of $16.3 million. This exhibit identifies the
20 adjustments necessary to reflect an "apples-to-apples"
21 comparison to the preliminary estimate, and to reflect cost
2 Network Optization - In the early stages of AM deployment, only low power output radio frequency
meters were available. In later stages of the deployment the power output of the radio frequency meters
was increased substatially. Experience has shown that when deployig a network over the low power
meters, network optimzation wil have to occur. The optization may tae the form of moving or
adding network components. In other cases, the only alterntive may be to replace the low power radio
frequency meters with high power versions.
Paulson, Di 15
Avista Corporation
1 changes due to design changes during implementation over
2 the past four years.The comparison shows that the
3 adjusted current estimate is 13.8% higher than the 2003
4 preliminary cost estimate.
5 Q.Please explain the adjustments reflected on
6 Exhibi t 12, Schedule 2.
7 A.As noted in the Company's direct testimony of
8 David D. Holmes in the 2004 filing, the preliminary
9 estimate was based on 2003 dollars. It was also noted that
10 the selection of appropriate technologies and vendors, as
11 well as refinement of cost estimates would take place in
12 2004. Specific adjustments reflected on the exhibit are as
13 follows:
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. Customer growth from 2003 to the end of the
project in 2008.
. Additional PLC meters required instead ofradio-based.
. Solid-state electric meters versus retrofittingelectromechanical meters.
. Actual fixed Company overhead costs that wouldhave been absorbed through other capi tal
proj ects if AM had not been deployed, and which
were not reflected in the preliminary 2003estimate.
. Actual AFUDC which was not reflected in the
preliminary 2003 estimate.
. 2005-2008 actual costs vs. 2003 nominal dollars
reflected in the preliminary estimate.
Q. Please provide further elaboration on the changes
31 during the course of deploying AM?
32 A.One of the changes was the increase in the numer
33 of customers in our Idaho service territory from the
Paulson, Di 16
Avista Corporation
1 initial estimate in 2003 to the end of the project in 2008.
2 The initial projections were based on a customer base of
3 approximately 171,000. As of this filing the customer base
4 is approximately 194,000.
5 Another change that caused higher proj ect costs was
6 the numer of meters that were deployed on the PLC system.
7 Preliminary projections were approximately for 28,000
8 meters. After more detailed system analysis was performed
9 in regard to substation configurations and operational
10 considerations, the numer of PLC meters deployed exceeded
11 40,000.The PLC system components are inherently more
12 costly than the radio-based systems, but are the only
13 viable solution in these lower meter density areas, for
14 reasons explained above.
15 Another component that caused higher proj ect costs was
16 the determination to utilize solid state meters versus
17 retrofitting electromechanical meters with a radio-based or
18 PLC module. Just prior to the beginning of the project, an
19 indus try-wide transition was being made away from
20 electromechanical meters to solid state meters. In an
21 effort to guard against technological obsolescence, Avista
22 also made the transition to solid state meters.
23 Q.Are there benefits surrounding the decision to
24 adopt solid state metering in Idaho?
Paulson, Di 1 7
Avista Corporation
1 A.Yes, these meters are more customer-friendly by
2 incorporating a digital display that is much easier to read
3 rather than a series of dials.Solid state meters also
4 provide a single self-contained unit that eliminates moving
5 parts.The most significant benefit was avoiding
6 technological obsolescence as discussed previously. During
7 the course of this proj ect deploYment, the market for
8 electromechanical meters has diminished significantly.
9 Very few if any current deploYments of AMR/AMI are
10 utilizing retrofit electromechanical meters.
11 Q.What is the overall impact of AM to Idaho
12 customers in this filing?
13 A.Including the capital costs associated with AM
14 through the end of 2008 in rates will translate into an
15 addi tional electric revenue requirement of $3,636,000, and
16 is part of the overall revenue request increase of
17 $32,328,000 in this case.It will also translate into an
18 additional natural gas revenue requirement of $1,091,000,
19 and is part of the overall revenue request increase of
20 $4,725,000 in this case. This is reflected in Company
21 witness Ms. Andrews' testimony and exhibits.
22 Q.What are the reductions in expense associated
23 with the AM installation?
24 A.The reduction in meter reading staff and related
25 transportation expenses are a result of the installation of
Paulson, Di 18
Avista Corporation
1 the AMR system.Annual meter reading costs (FERC account
2 902) declined approximately $545,000 for electric service
3 and $323,000 for natural gas service from 2004 to 2007.
4 In order to determine the estimated impact of AM to
5 Idaho customers over the expected service life of the
6 equipment, it has been assumed that traditional meter
7 reading costs would have escalated at an average of 3.5%
8 per year going forward from 2009, the rate year for the AM
9 proposal in this case.In other words, from an avoided
10 cost perspective, had AM not been installed in Idaho, the
11 Company assumed that a 3.5% average cost escalation for
12 tradi tional meter reading practices will have continued
into the future in order to reflect labor and13
14 transportation cost increases.Given this assumed
15 escalation over time, the cost savings associated with the
16 elimination of tradi tional meter reading practices
17 approximate $16.5 million over 20 years for electric
18 service and approximate $6.7 million over 15 years for
19 natural gas service. The Company assumed that the expected
20 life of the solid state electric meters is 20 years,
21 therefore the expected meter reading savings related to the
22 electric AM system were calculated over 20 years.The
23 Company also assumed that the expected life of the ERT
24 modules installed on gas meters will have an average life
25 expectancy of 15 years, therefore the meter reading savings
Paulson, Di 19
Avista Corporation
1 related to the gas AM system were calculated over 15 years
2 as well.
3 Q.Has the Company reflected cost savings already
4 realized with AM in its pro form case?
5 A.Yes. The savings in meter reading expense due to
6 reduced labor and transportation were all realized by the
7 2007 test year.
8 Q.Do these cost savings reflect other non-
9 quantified benefits discussed previously?
10 A.No, they do not.There have been a variety of
11 non-quantified benefits as described above. These include:
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. provides the foundation for later adoption of
retail electric energy pricing that may vary by
hour of the day or day of the weeki
. provides interval metering datai
. will provide indications of tampering andinformation on outage conditions i
. enhances Avista' s ability to provide
consolidated billing statements for customers
with multiple accountsi
. eliminates the need for estimated reads i
. improves accuracy of customer billing because
estimates and misreads will be reducedi
. information obtained will be of value in
determining more efficient specifications fordistribution equipment used to serve Avista' scustomersi
. helps to manage operations during outages and
may prevent extended customer outagesi
. reduces or eliminates both regular and after-
hours service calls due to reconnecting or
disconnecting service at the meter i
. provides safer environment for our customers andemployees ¡and
. allows evaluation of the Company's Demand
Response programs.
Paulson, Di 20
Avista Corporation
1 Q.Does
2 testimony?
3 A.Yes, it does.
this conclude your pre-filed direct
Paulson, Di 21
Avista Corporation
1'!'CDl "J t.
DAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
"lfìM' ADri - q I?r'l \:, 08(.uUU Hi 1\ .. .
REGULATORY~
Ln':':~;,;';:.'" .
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-08-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-08-01
AUTHORITY TO INCREASE ITS RATES )
AN CHAGES FOR ELECTRIC AN )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 12
AN NATURA GAS CUSTOMERS IN THE )STATE OF IDAHO ) GREG A. PAULSON
)
FOR AVISTA CORPORATION
(ELECTRIC AN NATURA GAS)
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Exhibit No. 12
Case Nos AVU-E-08-01 &
AVU-G-08-01
G. Paulson, Avista
Schedule 1, p. 1 of 1
AVISTA UTILITIES
Advanced Meter Reading Project Costs
Estimated Cost of AMR through December 31, 2008
Less:
1) Meter Installations for new Customers
2) Additional PLC Meters Required Instead of Radio-Based
3) Solid State vs. Electromechanical Meters
4) Allocation of Fixed Company O/H
5)AFUDC
Total Adjusted Costs
2003 Preliminary Estimate
6) Difference in Estimate Based on "Apples-to-Apples" Comparison
Percent of Preliminary Estimate
$28,762,199
635,000
1,100,000
600,000
2,775,070
5,105,814
$18,546,315
$16,300,000
$2,246,315
13.8%
1) Increase in the number of customers in our Idaho service territory from the initial estimate in
2003 to the end of the project in 2008. The initial projections were based on a customer
base of approximately 171,000. As of this filng the customer base is approximately 194,000.
2) Higher project costs due to the number of PLC meters that were deployed on the system.
Original projections were approximately for 28,000 meters. After more detailed system
analysis was performed in regard to substation configurations and operational
considerations, the number of PLC meters deployed exceeded 40,000. The PLC system
components are inherently more costly than the radio-based systems, but are the only viable
solution in these lower meter density areas, for reasons explained in the testimony. The
additional costs include the higher costs of the meters and the labor associated with the
installation. Further costs include the number of additional substations requiring the PLC
communication equipment.
3) Determination to utilze solid state meters versus retrofitting electromechanical meters with a
radio-based or PLC module. Just prior to the beginning of the project, an industry-wide
transition was being made away from electromechanical meters to solid state meters. In an
effort to guard against technological obsolescence, Avista also made the transition to solid
state meters.
4) The preliminary estimate included the cost of installing the system, and did not include an
allocation of fixed company overheads.
5) The preliminary estimate included the cost of installing the system, and did not include
AFUDC.
6) The preliminary estimate was made using 2003 nominal dollars. Actual costs reflect
increases due to inflation since the 2003 preliminary estimate. The Company also noted in
its testimony from the last rate case that the estimate was "initial" or preliminary, and noted
that, "Specific system design, vendor evaluation and selection will take place in 2004."
Exhibit No. 12
Case Nos A VU-E-08-01 & A VU-G-08-01
G. Paulson, Avista
Schedule 2, p. 1 of 1