20070502Phase I AMI Implementation Status Report.pdf

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IDAHO~POWER~
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An IDACORP Company
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MAGGIE BRILZ
Director, Pricing
May 1 2007 1: ~C - E - 06-
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 West Washington Street
PO Box 83720
Boise, Idaho 83720-0074
Re:Phase One AMI Implementation Status Report
Dear Ms. Jewell:
Enclosed please find eight copies of Idaho Power s Phase One AMI Implementation Status
Report. This report is filed in compliance with Idaho Public Utilities Commission Order No.
30102.
The Company previewed the information included in this report with Commission Staff on April
23. As stated in the report, the Company is committed to filing a supplement to this report no
later than September 1 , 2007 detailing the results of its in-depth financial analysis and the
specifics on how it will proceed with AMI deployment.
If you have any questions regarding this report, please do not hesitate to contact me.
Sincerely
cc:Ric Gale
O, Box 70 (83707)
1221 W Idaho St.
Boise, ID 83702
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IDAHO~POWER~
An IDACORP company
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Advanced Metering Infrastructure (AMI)
Status Report
Presented by Idaho Power Company
and the Idaho Public Utilities Commission
May 2007
For clarity of understanding, the term AMR (Automated Meter Reading) has been upgraded to
AMI (Advanced Meter Infrastructure), which better reflects the capabilities of the technology
discussed in this report.
Table of Contents
Acronyms and Definitions
.............................................. ..............
........ ..... iii
Part 1-Executive Summary ......................................................................
1. Purpose ......................................................................................................................
2. Progress Summary.
.............. ..................... ........................ .......... ............ ....... ....... ....
3. Updated Cost/Benefit Analysis.................................................................................
4. Conclusions and Future AMI Implementation .........................................................
Part 2-Status of AMI Phase One ..............................................................
1. Background & Procedural History...........................................................................
2. Scope of Phase One ....................................................................................
:.............
3. Status of Next Steps Identified in December 2005 Status Report .........................
A. Specific Activities ............................................................................................................................
B. Status of the Meter Data Management System ................................................................................ 7
C. Other Issues Further Investigated................... .................. ............................... .......... ............ .......... 7
4. AMI Benefits.......... ...............
............................................... ............................ ..... ......
A. General Discussion .........................................................................................................................
B. Quantified Benefits of AMI........................... ........................................... ................. .......... ....... ....... a
C. Unquantifiable Benefits of AMI......................................................................................................
D. Potential Benefits Unlikely to Provide Significant Value .................................................................
E. AMI Benefits to Demand Side Management Programs ..................................................................
5. Conclusions and Future AMI Implementation .......................................................
Idaho Power Company
Idaho Power Company
Advanced Metering Infrastructure Status Report Acronyms and Definitions
Acronyms and Definitions
Due to the technical nature of this document, many abbreviations are used throughout to enhance
readability. To avoid any confusion, use the table below as a guide to the acronyms and
defmitions of the terms used in this report.
Acronym Description Definition
AMR Advanced Meter Reading
AMI Advanced Metering
Infrastructure
CIS Customer Information
System
DCSI Distribution Control
Systems, Inc.
Energy Watch
lEE Itron Enterprise EditioncID
IPC Idaho Power Company
IPUC Idaho Public Utilities
Commission
MDMS Meter Data Management
System
MIRA Multiple Input Receiver
Assembly
The components necessary to read a meter remotely
using technology to retrieve meter-reading data through a
one-way communication network.
Latest terminology for AMR to better reflect the expanded
capabilities of two-way communication network. AMI
systems measure, collect, and analyze energy usage
information from advanced metering devices through
various communication media. The infrastructure includes
hardware, software, communications equipment, customer
associated systems and data management software.
Idaho Power s billing and customer system that contains
all customer data utilized by Idaho Power employees to
provide functionality for customer-related events such as
billing, rates, service orders, and meter reading.
The vendor who sells the AMI power-line-carrier system
Idaho Power implemented during the Phase One project.
The Critical Peak pricing program Idaho Power
implemented in the Emmett area in 2005.
The Itron product name of the Meter Data Management
System Idaho Power purchased for the Phase One
project.
A system that manages meter-reading data intended to
validate the accuracy and completeness of the data and
provide estimating routines to create billing-quality data.
The system is also intended to compile the data to billing
intervals for time-variant pricing programs.
Substation hardware that enables communication on
multiple distribution feeders and phases at the same time
reducing the time it takes to locate and communicate with
transponders.
Idaho Power Company iii
Advanced Metering Infrastructure Status Report Acronyms and Definitions
Acronym Description Definition
MVRS Manual Meter-Reading
System
NEXUScID Nexus Energy Software
TNS TWACScID Network Server
TOD Time-of-Day
TWACScID Two-Way Automatic
Communication System
VEE Validate, Estimate, Edit
VSD Variable Speed Drives
Extended Memory
The software package and equipment Idaho Power
purchased from Itron that facilitates the current manual
meter reading process. This consists of the handheld
devices that are used to collect the existing meter-reading
data and the software to feed the information to the CIS.
A hosted, Internet-based tool that Idaho Power contracted
with Nexus Energy to provide customers with access to
their hourly energy usage via the Idaho Power Web site.
This is the host software sold by DCSI that controls the
signaling of information between the meter through
power-line-carrier.
The Time-of-Use pricing program Idaho Power
implemented in the Emmett area in 2005.
The DCSI AMI system Idaho Power installed during Phase
One. The system uses power-line-carrier technology to
communicate with the meter.
A primary functional requirement of the MDMS system to
validate meter data for accuracy and completeness and
provide estimates for any missing interval data. This
function also provides validation of any anomalies in the
data and edits the data accordingly to achieve
billing-quality data.
Customer equipment at the meter location that allows the
customer to change the load of energy required to operate
a piece of equipment.
A new meter transponder module developed by DCSI for
TW ACScID that has a rolling 7 days of hourly data stored in
memory.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 1-Executive Summary
Part 1-Executive Summary
1. Purpose
Idaho Power Company (IPC) implemented a Phase One Advanced Metering Infrastructure
(AMI)l System in 2004. A status report detailing the progress made and issues identified during
Phase One, as well as IPC's two-year action plan for further evaluation and issue resolution, was
filed with the Idaho Public Utilities Commission (IPUC) on December 30, 2005. As a result of
its review of the Phase One status report, the IPUC issued Order No. 30102 directing IPC to file
a report no later than May 1 , 2007 specifically addressing the following issues:
A. Progress made on each issue identified in the Next Steps section of the December 2005
Status Report. The issues described in the Next Steps section centered around two main
areas:
1. Status ofTW ACSiS) System Issues;
2. Status of MDMS Software Issues.
B. A more extensive analysis of potential benefits and costs.
C. An assessment of how IPC will proceed with AMI deployment, including an implementation
time line.
2. Progress Summary
IPC has been very active improving upon the AMI system installed in Phase One. IPC has
implemented numerous software upgrades and hot fixes in the past year and a half, the most
significant of which was the Version 5 upgrade to the Meter Data Management System (MDMS)
software. As a result of these efforts, all outstanding issues described in the previous report have
been resolved, with the exception of the issue regarding meter compatibility with variable speed
drives (VSD). IPC does not see this issue as a barrier to expanding AMI since relatively few
VSD installations affect our metering equipment.
3. Updated Cost/Benefit Analysis
While IPC continues to consider other technologies, including a hybrid solution for AMI, at the
present an AMI system utilizing TW ACS~ appears to meet the functional requirements for much
of our service area. IPC is updating its in-depth fmancial analysis to incorporate revised pricing
from various vendors for the system components needed to install AMI and to incorporate
updated benefits examined during the past 15 months. In its December 2005 status report, IPC
indicated its plan to conduct an in-depth financial analysis during the second half of 2007.
1 The term AMI refers to systems that measure, collect, and analyze energy usage information from advanced
metering devices through various communication media on request or on a pre-defined schedule. This infrastructure
includes hardware, software, communications equipment, customer associated systems, and data management
software.
Idaho Power Company
Part 1-Executive Summary Advanced Metering Infrastructure Status Report
Following the IPUC's order directing IPC to ftle a report not later than May 1 , 2007, IPC
accelerated this analysis time line. However, IPC has not been able to complete the analysis in
time to include the results in this report. A comprehensive fmal analysis will be completed no
later than September 1, 2007 and included in a supplemental ftling to the IPUc.
4. Conclusions and Future AMI Implementation
Resolution of the technology issues discussed in the Phase One report is critical for success of
AMI and was required before further implementation can occur. IPC has been very active
improving upon the AMI system installed in Phase One. As a result of these efforts, all
outstanding issues described in the December 2005 report have been resolved with the exception
of the issue regarding meter compatibility with variable speed drives (VSD). IPC does not see
this issue as a barrier to expanding AMI since relatively few VSD installation affect our metering
equipment and the vendor has delivered a solution that IPC is currently testing.
IPC is in the process of updating its in-depth fmancial analysis. This analysis will include several
deployment scenarios as well as revised product pricing and benefit valuation. IPC will submit to
the Commission no later than September 1 , 2007 , a supplement to this report detailing its
assessment of how it will proceed with AMI deployment.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
Part 2-Status of AMI Phase One
1. Background & Procedural History
IPC implemented an AMI! System in 2004. A status report detailing the progress made and
issues identified during Phase One as well as the Company s two-year action plan for further
evaluation and issue resolution was filed with the IPUC on December 30, 2005. As a result of its
review of the Phase One status report, the IPUC issued Order No. 30102 directing IPC to file a
report no later than May 1 , 2007 specifically addressing the following issues:
A. Progress made on each issue identified in the Next Steps section of the December 2005
Status Report. The issues described in the Next Steps section centered around two main
areas:
1. Status ofTW ACSQ!) System Issues:
Install necessary software upgrades;
Evaluate new substation equipment to increase bandwidth ability;
Evaluate new extended memory meter modules;
Resolve 480-volt meter reading issue;
Resolve issues concerning meter failures on variable speed drive customer
equipment;
Evaluate primary metering with the AMI vendor;
Further evaluate tamper detection (energy theft detection) data;
Evaluate the outage management abilities of AMI to identify operational benefits;
Further investigate a solution for single-phase substations;
Investigate AMI performance while substation maintenance occurs.
2. Status of Meter Data Management System (MOMS) Software Issues:
Install Version 5.0 and conduct a functional test;
Resolve issues concerning MDMS' ability to process hourly data for the two
time-variant pricing programs implemented in Phase One.
1 The tenn AMI refers to systems that measure, collect, and analyze energy usage infonnation from advanced
metering devices through various communication media on request or on a pre-defined schedule, This infrastructure
includes hardware, software, communications equipment, customer associated systems, and data management
software.
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
B. A more extensive analysis of potential benefits and costs.
C. An assessment of how IPC will proceed with AMI deployment, including an implementation
time line.
2. Scope of Phase One
AMI was installed in IPC's Emmett and McCall operating areas. AMI installation in the Emmett
operating area included the communities of Emmett, Sweet, Montour, Horseshoe Bend, Banks,
Crouch, Garden Valley, Lowman, and the surrounding rural areas of these communities. AMI
installation in the McCall operating area included the communities of McCall, Lake Fork
Donnelly, Cascade, New Meadows, Riggins, and the surrounding rural areas of these
communities.
AMI was installed for residential and small and large general service customers. During Phase
One, 23,474 AMI meters were installed with 10,742 AMI meters installed in the Emmett
operating area and 12 732 meters installed in the McCall operating area. This deployment
represented 97% of the total meters in the Emmett and McCall service areas.
Since the completion of the Phase One implementation in 2004, an additional 2 500 AMI meters
have been installed in the Emmett and McCall areas due to customer growth. Also, TW ACS(ID
equipment has been installed in one more substation bringing the total to nine.
The Phase One AMI project included the installation of the following systems:
TW ACS(ID System-This system, supplied by Distribution Control Systems Inc.
(DCSI) is a Two-Way Automatic Communication System (TW ACS(ID) consisting of
software and physical equipment located in the field. This system utilizes
power-line-carrier technology to communicate with meters and other TW ACS(ID
enabled equipment. This is the data collection system.
Itron Enterprise Edition (IEE)(ID Meter Data Management System (MDMS)-
This software system is the data management system for validating, editing, and
estimating hourly consumption data retrieved by the TW ACS(ID system and
converting this interval data into billing quantities for time-variant pricing
programs. In addition, the MOMS is the data source for other operational needs
such as outage management, load research, customer usage information, etc.
Nexus Energy Software-This Internet-based software system is the data
presentment system through which customers can access their energy use data using
the IPC Web site (www.idahopower.com).
Figure 1 illustrates how each of these three systems function within IPC' s overall AMI system.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
Idaho Power AMI System
TWACS(8) Substation
Control Equipment
CustomerInformation
System
Transmission
Power Lines
Distributionsu....tiD
Electric Service ToCustomer
Meter DataManagement
;:~r:n s
:~~er
AMR Data
/available via
Nexus on
idahopower.com
Remote TWACS(8) Device:
Meter Transponder or
Load Control Transponder
Distribution
Power
Lines
Figure 1 Idaho Power Company s AMI System
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
3. Status of Next Steps Identified in December 2005 Status Report
A. Specific Activities
During the past 15 months, IPC has investigated and evaluated the issues identified in the
December 2005 Status Report. Following is the current status of each issue.
TW ACS(8) Software Upgrade-IPC has performed numerous TW ACS(8) Network
Server (TNS) software upgrades and hot flXes in the past year and a half. The
current version in service is TNS 2.4. All known issues have been resolved and the
software is performing as expected. IPC is investigating the next generation of TNS
software in order to remain current with this evolving technology.
Bandwidth Capability-Since the initial deployment of Phase One, DCSI
developed and made available the Multiple Input Receiver Assembly (MIRA) for
installation at the substation. IPC installed and evaluated MIRA. This enhancement
improved the speed of data retrieval and reduced the frequency of missing hourly
data.
Extended Memory (XM) Modules-IPC purchased, installed, and tested meters
with extended memory (XM) modules. The module has been successful in
retrieving historic data. This new feature will enable time-variant rates.
480 Volt Meters-All existing 480-volt meters in the Phase One deployment areas
were retrofitted with new hardware that solved IPC's issues with those installations.
No further problems have been reported on 480-volt meter installations since the
retrofit.
Variable Speed Drive (VSD) Compatibility-IPC is still working with DCSI to
resolve the meter failure issues associated with VSD compatibility. IPC has
installed the latest hardware revision and is currently testing it in the field. As a
result of these efforts, all outstanding issues described in the previous report have
been resolved, with the exception of the issue regarding meter compatibility with
variable speed drives (VSD). IPC does not see this issue as a barrier to expanding
AMI since relatively few VSD installations affect our metering equipment, and the
vendor has delivered a solution that IPC is currently testing. IPC and DCSI are
dedicated to resolving the issue associated with VSDs.
Primary Metering-Since the initial deployment of Phase One, DCSI developed
and made available a TW ACS (8) solution for primary metered customers. IPC
installed and evaluated the primary metering equipment. The solution is working
well and IPC is satisfied this issued is resolved.
Tamper Detection-IPC has evaluated the TW ACS(8) tamper detection data over
the past year and has determined that the value of tamper data could be enhanced
with further development of additional analysis tools. IPC will research the
availability and capability of tamper detection software.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
Outage Assessment-IPC has used DCS!'s outage assessment software for the
past two years for cycling air-conditioners and for the analysis of the TW ACS
power outage management capabilities. IPC is confident that the outage assessment
software can enhance IPC's outage management capabilities as AMI is expanded
system-wide.
Single-Phase Substations-After further evaluation of the single-phase substation
solution, IPC has determined TW ACS ~ is not cost effective for stations that serve a
small number of customers. This is true for three-phase or single-phase substations.
None oflPe's single-phase stations serve enough customers for TW ACS~ to be
economically feasible. Therefore, IPC will analyze other technologies for use in
these areas.
Temporary Substation Transformers-IPC used mobile transformers and
temporary TW ACS~ installations during the upgrade of the Cascade substation and
during the replacement of the metal-clad switch gear at Emmett substation. In both
cases the system and equipment performed adequately and no significant issues
were encountered.
B. Status of the Meter Data Management System
The IEE~ MDMS was not functional during Phase One, requiring manual intervention for bill
processing associated with the two time-variant pricing programs offered in the Emmett area.
IPC has worked continuously with Itron since beginning deployment of Phase One. IPC stated in
the December 2005 Status Report that a solution to the MDMS issue was expected to be
implemented in April of 2006. IPC has tested and implemented numerous versions of this
quickly developing software. The work has focused mainly around developing and testing the
complex algorithms required to Validate, Estimate and Edit (VEE) hourly energy use data to
support time-variant rates. After steadfast dedication by IPC and Itron employees, IEE~ version
5, revision 11 was implemented in March of 2007. The software now has the specific
functionality to support time-variant pricing, including critical-peakpricing. IPC is collecting
hourly energy-use data on all 25 000 customers in the Phase One deployment area and
supporting the Time-of-Day (TaD) and Energy Watch (EW) programs offered in the Emmett
area by providing validated billing data to our billing system. IPC is working closely with Itron
to insure the needs for functionality and scalability are addressed in future software releases.
IPC is currently developing daily work processes and the system functionality to support
high- volume data validation and processing for billing.
C. Other Issues Further Investigated
While IPC continues to consider other technologies, including a hybrid solution for AMI, at the
present an AMI system utilizing TW ACS~ appears to meet the functional requirements for much
of our service area. IPC is updating its in-depth fmancial analysis to incorporate revised pricing
from various vendors for the system components needed to install AMI. Variouse
implementation scenarios will be evaluated as part of the financial analysis.
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
IPC has further investigated, identified, and quantified benefits available from AMI. Detailed
results of this benefit investigation are included in Section 4.
4. AMI Benefits
A. General Discussion
Benefits of AMI can vary significantly from utility to utility based upon each utility s existing
cost structure, geography, and customer base. IPC has investigated the benefits associated with
AMI. Those benefits have been categorized as:
Quantified (those for which a specific value has been determined);
Unquantifiable (those for which a value is recognized, but for which an amount
cannot be determined);
Benefits not likely to provide significant value.
B. Quantified Benefits of AMI
Metering Operational Benefits
Meter reading operations change significantly through the introduction of AMI technology. IPC
was able to identify the following benefits associated with full implementation of AMI:
Reduction of the manual meter-reading workforce;
Reduction of the Manual Meter-Reading System (MVRS) software-maintenance
fees, hand-held data-collector maintenance fees, and repair costs;
Elimination of erroneous meter readings are essentially eliminated reducing the
number of re-read orders;
Reduction of estimated meter readings due to access or weather issues are reduced;
Elimination of the need to perform remote connect/disconnects in the field (this
benefit requires additional devices and investment in order to be realized);
Reduction of vehicle purchases, maintenance, and fuel costs associated with the
manual meter reading process;
Reduction of safety incidents and accidents that occur while performing metering
functions in the field (reading, connect/disconnect and maintenance);
Elimination of field visits for move-in/move-out orders that do not physically
require a meter connect or disconnect;
Enhanced ability to identify failed meters within 24 hours.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
Customer Service Benefits
Based on Phase One, full implementation of AMI is estimated to result in a reduction in full-time
employees at !PC's Customer Service Center. This benefit is derived from the following:
Reduction in the cost associated with customer calls due to the reduction in
erroneous bills, improved credibility with customers, fewer billing complaints filed
with the IPUC, and the reduction in call length due to the availability of more
energy use data.
Reduction in time spent in the Customer Service Center reviewing exception reports
from manual meter reading, issuing orders, and completing billing adjustments due
to erroneous readings and estimated readings.
Outage Restoration Benefits
Communication with the meter provides two types of information that are useful in outage
situations. The flfSt being, a communication response from the meter signifies there is an
electrical connection to the customer and power is available at the customer s premises.
Conversely, a lack of communication with the meter indicates that power may not be available.
a. Restoration Confirmation
Typically, crews respond to an outage situation and the problem is one isolated event.
Frequently, however, there are multiple events that are not apparent to the Lineman. AMI
equipment can be used to verify that all customers are back in service before the Lineman or
Line Crew leaves the location, thereby eliminating a return trip and restoring power to the
remaining customers sooner.
b. A voided Disvatch
The AMI System can verify if the cause of the outage is due to a problem with IPC facilities.
Customers who call with a power outage often are unaware of the cause of the problem. If the
cause of the outage is actually the customer s equipment, the customer needs to hire an
electrician to make repairs. If IPC receives a reply after pinging the meter, then IPC and the
customer are assured that the electrical problem involves the customer equipment. IPC
responded to 2 588 such calls in 2006.
Often during a power outage situation, Line Operation Technicians are called to assist the
Lineman and/or Line Crew. AMI has the ability to "ping" the meters, and that provides
information to determine the scope of the outage. IPC anticipates that with a more clear
defmition of the outage that there will be a reduction in the number of times it is necessary for
the Line Operation Technicians to be involved with the outage.
c. Overloaded Equipment
At times transformers are overloaded from customer load. As a result, the fuse on the
transformer melts and the circuit is broken, as designed. In these situations, a trouble call is
dispatched, the fuse is replaced, and the transformer is potentially replaced as well. With AMI
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
data, the amount of actual load on a transformer could be compared to the transformer size and
the transformer could be replaced prior to the fuse melting. IPC's typical procedure is for the
Lineman to replace the fuse and then the next day the crew would replace the transformer. With
AMI overload data, the trouble call would be eliminated and a second outage for the customer
avoided.
Distribution Engineering and Operations Benefits
AMI has the ability to provide voltage and the energy-load data for each distribution circuit,
thereby allowing IPC to optimize the planning and operation of the distribution system. Also
AMI can work in concert with IPC's outage management system to improve the accuracy of
customer outage data.
Irrigation Peak Rewards Program
Currently, our Irrigation Peak Rewards program utilizes electronic timer switches to turn-off
irrigation pumps at specified intervals. Each year the customer chooses to change his
participation the timers have to be manually reprogrammed in the field. With AMI technology at
these locations, the timer could be remotely controlled and a field visit would not be necessary to
customize the switches to satisfy the customer s needs.
C. Unquantifiable Benefits of AMI
Unquantifiable benefits are those AMI-related benefits that don t translate into manpower
reductions or some other form of actual cost savings for IPc. The unquantifiable benefits include
the following:
Customer Satisfaction
AMI deployment results in increased customer satisfaction in several areas:
Customers will no longer need to provide IPC access to meters located on their
property on a monthly basis. This access requires customers to control their pets
and to locate fences and other objects so as not to conflict with IPC's access. In
addition, having a stranger on one s property causes irritation for some customers.
More accurate bills due to elimination of meter reading errors and estimated bills.
Flexibility to participate in a time-variant pricing program if desired. Large-scale
time-variant pricing programs will require additional investment in our Customer
Information System (CIS).
Energy-usage data made available to customers to help them make educated
decisions regarding their energy usage.
AMI's ability to communicate with the meter will help validate that all services
have been restored following an outage, rather than waiting for the customer to call
again.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
Reduced Read-to-Pay Time
The manual read process allows for a three day period to collect the meter data and convert the
data into a bill for the customer. With AMI, there is potential to reduce this time and therefore
gain a one-time improvement in IPC's cash flow. IPC questions whether this one-time benefit
will actually be realized. Those customers who pay their bill on a certain date every month may
find that receiving their bill a couple days sooner probably won t effect when they pay.
Meter Operations-Theft Detection
The AMI technology offers features that assist in investigating potential instances of energy
theft. These features are helpful, but are not expected to solely result in any significant cost
savings. Some utility companies have identified as much as a 1 % increase in revenues due to
improved theft detection. However, during the Phase One AMI deployment very few instances
of energy theft were discovered while performing approximately 24 000 meter exchanges and
inspections. In addition, IPC is cautious about a potential increase in attempted theft when IPC
employees are no longer visiting customer premises monthly.
High BilVEnergy Cost Inquiries
More accurate, timely data provided by AMI enables faster resolution of billing questions.
Additional Pricing Options
The more detailed usage information made available by AMI, whether it is hourly, daily, or
grouped into time blocks, can provide customers with useful information to make informed
decisions and more directly manage their energy consumption. The ability to capture individual
customer usage data on an hourly basis allows for a adoption of alternative pricing structures to
provide price signals to customers that encourage changes in usage patterns. Even small changes
in consumption due to modifications in price signals could provide significant benefits.
Implementing an AMI system that enables time-variant rates and other demand response
programs can help meet future energy demands.
D. Potential Benefits Unlikely to Provide Significant Value
The following potential benefits were reviewed by IPC and after careful consideration at this
time were deemed unlikely to provide a significant benefit:
Sale of used meters-Replacement of meters during AMI implementation allows
for the used meters to be sold to other electric utilities. The bulk of meter purchases
today are solid-state electronic meters. With many utilities looking toward
implementing some form of advanced metering, there is very little value in used
mechanical meters.
Summary Billing-Customers with multiple accounts and a summary bill could
have the meters read and usage billed quicker with AMI. There are relatively few
summary-bill customers, so this benefit has very little value.
Selectable bill date and bill frequency-The ability of AMI to daily obtain
customer usage potentially allows for customer choice of billing date and
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
frequency. While this is a potential customer benefit this option possesses some risk
of increased costs. IPC does need to maintain a somewhat uniform distribution of
billing dates throughout the month in order to achieve system efficiency.
Meter reading for other utilities-With specific enhancements, the AMI system
has the capability to read other utility meters (gas, water, etc.). While this is a
potential benefit, IPC has not had any discussions with other utilities or AMI
vendors to quantify the likely increases in AMI licensing and maintenance costs.
Load research equipment-AMI has the potential to provide hourly data for all
customers. This could eliminate the need for customer load research meters that are
used to sample and predict energy use characteristics. However, customer load
research recently began collecting volt-amp reactive measurements for residential
services. The typical residential AMI meter does not currently provide this data.
Optimized transformer and service wire sizing-AMI can provide customer
specific energy usage profiles and therefore the transformer and service wire can be
optimized for delivering energy consumed by the customer with higher reliability.
There is a cost balance to be considered between fewer standard sizes of
transformers and service wires versus numerous custom-sized transformers and
service wires. Customization also limits operational flexibility as system loads
change over time.
End-of-Line Voltage-Upon request, line voltage can be retrieved for a limited
number of commercial meters, thus ensuring quality of service for the customer.
This will benefit in determining when upgrades to the distribution system are
necessary.
Power factor losses-With additional investment, TWACS QY can deliver power
factor data on a limited number of commercial meters. This enables administering
more equitable rates. This has very limited potential benefit since IPC already
recovers its costs in the existing rates. This may be a shift between customers, but
neutral to IPc.
Power quality monitoring-With additional investment, TW ACSQY can deliver
basic power quality data for a limited number of commercial meters. AMI can
promote good power quality information, but actual power quality monitoring
equipment is much more sophisticated and collects far more data than TW ACS
can transmit.
Distribution Automation-With additional investment, TW ACSQY has the ability
to remotely control and communicate with distribution equipment such as reclosers,
capacitors and generators. IPC has an existing radio-controlled capacitor system
that will not be replaced by TW ACSQY until the end of the existing equipment's life.
Market segmentation and targeting-AMI's ability to provide hourly usage data
for all customers helps identify homogenous subgroups within traditional customer
classifications that can be used for developing targeted programs.
Idaho Power Company
Advanced Metering Infrastructure Status Report Part 2-Status of AMI Phase One
E. AMI Benefits to Demand Side Management Programs
IPe's two demand response programs-AiC Cool Credit and Irrigation Peak Rewards-utilize
switches to turn off customer load, thereby managing peak loads on IPe's system. Although
TW ACSIS) can provide the same service with the added benefit of two-way communication with
each switch, it does not appear to be cost effective to replace the existing system with TW ACS IS)
IPC offered the TaD and EW Pilot Programs in the Emmett Yalley again during the summer of
2006. A report detailing the results of the programs was filed with the IPUC on February 28,
2007. While EW, a critical peak, time-variant pricing program, provided a statistically significant
change in customer usage patterns, the TOD program did not. IPC is currently evaluating the
potential benefits available through the EW Program.
5. Conclusions and Future AMI Implementation
Resolution of the technology issues discussed in the Phase One report is critical for success of
AMI and was required before further implementation can occur. IPC has been very active
improving upon the AMI system installed in Phase One. As a result of these efforts, all
outstanding issues described in the December 2005 report have been resolved with the exception
of the issue regarding meter compatibility with variable speed drives (YSD). IPC does not see
this issue as a barrier to expanding AMI since relatively few YSD installation affect our metering
equipment and the vendor has delivered a solution that IPC is currently testing.
IPC is in the process of updating its in-depth financial analysis. This analysis will include several
deployment scenarios as well as revised product pricing and benefit valuation. IPC will submit to
the Commission no later than September 1 , 2007, a supplement to this report detailing its
assessment of how it will proceed with AMI deployment.
Idaho Power Company
Part 2-Status of AMI Phase One Advanced Metering Infrastructure Status Report
Idaho Power Company