HomeMy WebLinkAbout20030509AMR Report.pdfAn IDACORP Company
HECEIVED
IDAHO POWER COMPA~~ \ 1 r: f)O. BOX 70
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BOISE IDAHO83707
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2003 ~1~ 'f -9 rl '1
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UTiL\T\ES COMMISSION
May 9,2003
BARTON L. KLINE
Senior Attorney
Ms. Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise , Idaho 83720-0074
Re:Case No. IPC-02-
In the Matter of the Investigation of Time-of-Use
Pricing for Idaho Power Residential Customers
Dear Ms. Jewell:
Among other things, Commission Order No. 29226 directs Idaho Power
Company "to file the original AMR report relating to the Company s Idaho City pilot
program with the Commission . Idaho Power believes a misunderstanding of the
analyses performed by the Company regarding automated meter reading (AMR) exists
and thus the appropriate analysis to be included as part of the record in this case was not
identified in Order No. 29226. Idaho Power hopes to clear up this misunderstanding and
believes the analysis herewith filed provides the desired information.
Idaho City Pilot
In 1998 Idaho Power pilot tested the installation and operation of the
TW ACS~ power line carrier AMR system in the Idaho City area. This pilot was intended
to provide to Idaho Power information on the potential viability of the technology to
operate on one of the Company s longest feeders. Idaho Power did not make an
application with the Commission requesting cost recovery or ratemaking treatment of any
of the costs associated with this pilot. Rather, the Company met with Commission Staff
to inform them of the details of the pilot so that they could respond to any inquiries they
might receive from affected customers. In addition , the Company invited Staff to its
offices to experience first hand the AMR process of contacting customer meters and
gathering usage data. During this visit the Company informed Staff that the pilot had
been successful in its sole purpose, Le., testing the technology.
The Commission did not request that the Company file a report with the
Commission detailing the results of the pilot. However, in order to minimize confusion
regarding the Idaho City Pilot evidenced in Order No. 29226, the following is the write-up
of the pilot results prepared for the Company s management in 1999:
Telephone (208) 388-2682 Fax (208) 388-6936, Email BKline(PJidahopower.com
Ms. Jean D. Jewell
Page #2
May 9, 2003
In 1998 Idaho Power pilot tested the installation and
operation of the TWACS~ power line carrier AMR system.
That test involved the installation of TW ACS~ substation
equipment in one station bus section , 200 pilot meters
supplied by DCSI , as well as a follow-on installation of 1 000
additional meters that the Company s central test facility
retrofitted with TW ACS~ modules.
This pilot test proved that TW ACS , with reasonable
accommodation and limited expansion of infrastructure, can
communicate with the Asea Brown Boveri (ABB) meters-of-
choice. TW ACS~' zero-crossing modulated power line
carrier communications is not affected by terrain , distance
or line equipment. Neither communications failure nor failed
meters were experienced.
The TW ACS~ pilot test validated its deployability and
capability to meet the Company s basic technology
requirements:
demand reset instructible meters
0 ultra-high reliability
On-going changes in CIS prevented demonstration of
a commodious data interface with the customer information
system. Yet industry experience indicates that this will
certainly be the case. TW ACS~' open computing
architecture uses the same file formatting as does the Itron
system now in use for meter reading data delivery. The
customer accounting system would see little difference from
the meter data it now receives.
2002 Automated Meter Reading Analysis
Following the completion of the Idaho City Pilot in 1999, Idaho Power began
a limited-purpose analysis of the costs and benefits of installing AMR technology. The
purpose of the study was to gauge the overall potential benefits and costs associated with
an AMR system and to provide the Company s management with the high level
information needed to evaluate whether it was economic to proceed with plans for AMR
Ms. Jean D. Jewell
Page #3
May 9 2003
installation. In 2002 the analysis was updated to reflect the costs associated with the
then current customer counts and employment levels. The 2002 analysis focused on the
costs of installing an AMR infrastructure and the benefits associated with reduced O&M
but did not address the treatment of the capital investment in existing meters nor did it
address any costs associated with severing employment. In addition, the analysis did not
identify a specific implementation time frame. This updated analysis, the 2002
Automated Meter Reading Analysis , was made available to Commission Staff in response
to the First Production Request of Commission Staff and is the document referred to by
Staff in its Comments in this case and by the Commission in Order No. 29226.
2003 Automated Meter Reading Analysis
Order No. 29226 also directs the Company to file a current analysis of the
costs and benefits of the installation of an AMR system. This report is designated as
Automated Meter Reading Report , Idaho Power Company, May 2003" or "2003 AMR
Report.
Enclosed are an original and seven (7) copies each of the 2002 Automated
Meter Reading Analysis and the 2003 AMR Report. In order to maintain the
confidentiality of proprietary Company information (including information that could
compromise the Company s ability to successfully negotiate with AMR vendors), the
Company has marked and printed the proprietary portions of the 2002 and the 2003
Automated Meter Reading Analyses on yellow paper. Idaho Power and Commission
Staff have negotiated an acceptable Protective Agreement. Following Staff Counsel'
signature of that Protective Agreement, I would appreciate your obtaining a signed Exhibit
A to the Protective Agreement from each Commission Staff member who will be
reviewing the 2002 and 2003 analyses prior to disclosing them.
I would also appreciate your taking those steps necessary to separate and
store the 2002 and 2003 Automated Meter Reading Analyses in a secure location with
limited access and safeguarded from unauthorized disclosure. Your cooperation in this
regard is greatly appreciated.
We have also enclosed an original and seven (7) copies of a redacted
version of the 2003 AMR Report and a redacted copy of the 2003 AMR Report has been
mailed to Bill Eddy (Land & Water fund of the Rockies, P.O. Box 1612, Boise, ID 83701)
and Dan Delurey (Executive Director, Demand Response and Advanced Metering
Coalition (DRAM), P.O. Box 33957, Washington, DC 20033).
Ms. Jean D. Jewell
Page #4
May 9 2003
I would appreciate it if you would return a stamped copy of this transmittal
letter for our files.
~J~
Barton L. Kline
BLK:jb
Enclosures
RECEIVED
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2003 MAY -9 PM 4: 58
An IDACORP Company
iU,\i:J Pl!;::LIC
UTILITiES CO~\M,SSIOH
AUTO MATED METER READ IN G REPORT
IDAHO POWER COMPANY
MAY 2003
Case No. IPC-02-
May 9, 2003
Table of Contents
Overview and Recommendation
...--.....--..--....-..--....-----....--.--....-.-..---.-....-.-.....---.........-.....--.....
AMR System Functionality...._......._-_.......--_..........__.---...-...---.--.-.....-...............-.......-..----..........
Implementati on Timetable
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2003 Analysis Results
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2003 Anal ysis Assumpti ons .-
----------- -------.----
_000 ----------------------------------------. -------000.----.-------.-----
Advanced Features Requiring Additional Investment.m------------------..-.--------..----..------...-------
Potential Risks
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Cost Recovery of AMR Investment
_--.--.....----......-........---.....---......--......---..............-.---....--....
Recommendati on
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Appendices
Appendix A: Cost-Effectiveness of AMR Technologies ---..-------.-.--------------....---------------.--
Appendix B: Cost Components Inc1 uded in Analysis -----.-----------------------.------.---.---------000----
Appendix C: Detailed Fi nanci al Anal ysis --------000--------------.--
---------------.-------- ---------.-------- ------
Overview and Recommendation
Idaho Power Company has been monitoring and evaluating the potential costs and
benefits of Automated Meter Reading (AMR) technology since the mid-1990s. Given
the overan rural nature of Idaho Power s service territory, the average density of 83
customers per square mile, and the topography of southern Idaho, few AMR technologies
are capable of successfuny capturing and transmitting an customer usage infonnation
within our service territory. Idaho Power has identified two technologies - Fixed Radio
Network and Power Line Carrier - capable of meeting our system requirements. Of
these two, the Power Line Carrier (PLC) technology is the most cost-effective given the
geography and customer density of Idaho Power s service territory. For this reason
Idaho Power s evaluation of AMR has focused on the PLC technology. Appendix A to
this report includes a detailed comparison of the cost-effectiveness of fixed radio network
and PLC technologies and provides background for Idaho Power s decision to focus on
PLc.
The Company s current analysis of AMR evaluates a "plain vani11a" power line carrier
technology capable of replacing the functions currently perfonned by existing meter
reading technicians. These functions include capturing the usage infonnation
transmitting the usage infonnation to the Company s bining system for preparation of a
monthly bin , and detecting energy theft or diversion. While this "plain vani11a
technology wi11 provide the basis for time-variant pricing in that hourly usage can be
captured and transmitted, additional investment is necessary in order to implement other
than standard , or traditional , time-of-use pricing. The Company s analysis does not
include any cost components associated with the additional investment which would be
necessary to implement advanced pricing or other advanced AMR features. The decision
to focus the Company s analysis included in this report on a "plain vani11a" AMR system
is the result of discussions with Commission Staff fonowing the Commission s Public
Meeting held on March 20, 2003.
The Company s analysis has attempted to include an components of cost associated with
replacing existing metering equipment with advanced metering capability. Included in
these costs are such items as metering and substation equipment, employee severance
costs, amortization of the undepreciated investment in the existing meters , reductions in
O&M expenses related to a reduced work force, and costs specific to the identified four-
year implementation plan. Some of these costs have not been previously included in any
Company analysis of AMR, including the 2002 Automated Meter Reading Analysis
since the purpose of the previous analyses has been to simply provide an indication to the
Company s management of the potential viability of an AMR system and did not include
an implementation plan. A comparison of the cost components included in the current
analysis as wen as the 2002 analysis is included in Appendix B. In accordance with the
Commission s directive in Order No. 29226, the Company has also submitted to the
Commission the 2002 Automated Meter Reading Analysis.
The 2003 analysis perfonned by the Company indicates that the revenue requirement for
an AMR system is significantly higher than the revenue requirement for the current
metering system for the first seven years. After seven years the revenue requirement
associated with an AMR system is lower than the revenue requirement for the current
meter system. However in order to properly evaluate the time value of money issues
inherent when evaluating customer payments over a 40 year period, the Company used
its current after tax weighted average cost of capital of 7.241 % as a proxy for the cost
capital for present value calculation purposes. The average cost of money, or appropriate
discount rate, actually experienced by our customers over the 40 year period could be
very different from the discount rate used in the analysis. However, the Company
believes the current value of 7.241 % is a reasonable proxy for analysis purposes. The
Company s updated analysis of AMR indicates that over a 40-year time frame
implementing an AMR system instead of maintaining the current manual system for
reading meters has the potential to result in a present value revenue requirement
reduction of $ 32 758 268. However, during the first six years when the yearly revenue
requirement of AMR is greater than the current system, the present value of the revenue
requirement would be $31,498 713 greater with an AMR system than with the current
metering system. On a present value basis, the breakeven point (where the reduction in
revenue requirement resulting from full implementation of an AMR system outweighs
the initial increase in revenue requirement) is in year 2024. The Company believes that
the many risk factors associated with a 21-year payback for a technology-based
investment is too long a time period to justify recommending AMR implementation at
this time. Consequently, Idaho Power does not recommend proceeding with AMR
implementation at this time.
AMR System Functionality
The 2003 analysis addresses a power line carrier AMR system with the following
functi onali ty:
Capability to collect hourly meter readings daily from a remote location.
Remotely reads meters for computing beginning and ending bills as customers
and businesses move.
Provides two-way communications with meters connected to the power line.
Detects and alerts Idaho Power to possible energy theft.
Supports monthly billing of existing rates.
Supports monthly billing of "traditional TOU rates.
Implementation Timetable
Commission Order No. 29226 directed the Company to "
.. .
set out an implementation
timetable that institutes AMR first in areas Idaho Power and its customers will receive the
greatest benefits." Idaho Power has identified the following implementation schedule as
providing the greatest benefit. This timetable assumes a Commission Order directing
Idaho Power to proceed with AMR implementation is issued in September of this year.
Beginning April 2004
Payette, McCall, Mountain Home, Hailey, Mini Cassia, areas and the minimum
infonnation infrastructure investment. (Includes Cambridge, Council, Cascade
Glenns FelTY, Ketchum , Fairfield, Oakley) Total Cost - $20.1 Million
2005
Twin Falls, Jerome, Gooding, COC, Emmett areas. (Includes Hagennan, Buhl
Kimberly, Hansen, Shoshone, Wendell, Bliss, Nampa, Caldwell , Horseshoe Bend
Garden Valley and Lowman) Total Cost - $26.7 Million
2006
Boise area. (Includes Meridian , Kuna, Idaho City) Total Cost - $25.9 Million
2007
Pocatello, American Falls, Blackfoot, Salmon areas. Total Cost - $13.8 Million
The implementation timetable shown above meets the following deployment strategies.
. A six-month lead-time is needed to initiate the project and get equipment ordered.
Start with isolated areas that have a more favorable cost/benefit analysis, i.
Mountain Home, McCall, Hailey.
Start in a smaller impact area and perfect the deployment process before the full
ramp up necessary to complete the Nampa, Caldwell, Meridian , Boise areas.
Complete the deployment in contiguous areas to capture the full benefit of
reduced operational costs and minimize negative impact on customer service.
Automate operational areas where access issues (e., agricultural areas) are more
problematic before those areas where access is less problematic.
Spread the financial impact of this project to an approximate maximum of $25
Million per year.
. A four-year implementation plan will allow for a better transition to a reduced
workforce.
The meters removed from lower growth areas (Payette) can be reused in higher
growth areas (Boise, Nampa, Meridian) until automation occurs.
2003 Analysis Results
The total initial Capital Cost for the identified four-year implementation of an AMR
system is projected to be $86.5 Million. The Company calculated the yearly revenue
requirement over forty years for both an AMR system and the culTent manual meter
reading system. Table 7 in Appendix C contains the results of revenue requirement
calculations for each year of the 40-year analysis. Appendix C also contains the details
related to the calculation of the revenue requirement for both systems. Table 8 details the
calculations for the culTent standard manual system and Table 9 details the calculations
for the AMR system. Compared to the revenue requirement associated with the culTent
meter system, the revenue requirement for an AMR system would be $8.2 Million higher
in the first year of implementation (2004), $9.2 Million higher in Year 2 (2005), $9.
Million higher in Year 3 (2006), $9.1 Million higher in Year 4 (2007), and $1.1 Million
Higher in Year 5 (2008). The revenue requirement for an AMR system would continue
to be higher than the revenue required to support manual meter reading until 2010. The
revenue requirement for an AMR system would be less than the revenue requirement for
the manual meter system for the remaining 32 years of the analysis. However by 2010
our customers would have paid in excess of $37 million for the AMR system beyond
what they would have paid for the current manual system.
In order to properly evaluate the time value of money issues inherent when comparing
differing customer payments over a 40 year period, the Company used its CUITent after
tax weighted average cost of capital of 7.241 % as a proxy for the customer s cost of
capital for present value calculation purposes. The weighted average cost of money, or
the discount rate, actually experienced over the 40-year period could be very different
from the discount rate used in the analysis. To properly calculate the present value of the
revenue requirement, we would need to detennine the incremental borrowing rate (cost of
money) for each customer then weight customers' boITowing rate by their relative share
of total revenue requirement. This calculation of course would be next to impossible
hence the use of a proxy discount rate of 7.241 %. The Company s analysis of AMR
indicates that over a 40 year time frame , implementing an AMR system instead of
maintaining the CUITent manual system for reading meters has the potential to result in a
present value reduced revenue requirement of $ 32 758 268. However, during the four-
year implementation time frame, the present value of the revenue requirement would be
$30,864 220 greater with an AMR system than with the current metering system and non-
discounted incremental charges to customers of $35 629 570. Even after seven years,
when the yearly revenue requirement of AMR is less than the CUITent system, the present
value of the revenue requirement would be $31,498 713 greater with an AMR system
than with the CUITent metering system. On a present value basis , the breakeven point
(where the reduction in revenue requirement resulting from full implementation of an
AMR system outweighs the initial increase in revenue requirement) is in year 2024 or 21
years after installation.
Of course the Company does not know for certain what the true cost of money is for our
customers so in order to provide some sensitivity analysis regarding the true cost of
money, the Company also evaluated the present value of the yearly revenue requirement
for an AMR system and for the CUITent manual system with a discount rate of 5%, 10%,
11 %, and 12%. If our customers' incremental borrowing rate were as low as 5%, the
breakeven point would still be 19 years after installation. If our customers ' boITowing
rate were 10%, the breakeven point would be 30 years. If we discount the customer costs
by 11 %, the breakeven point is in year 37. Finally, if we use 12%, the breakeven point is
somewhere beyond our 40 year analysis.
One method the Company has employed to actually shorten the payback time frame for
an AMR system is to amortize the book value of the existing meters over the 4-year
AMR installation time frame. If the existing meters were to be amortized over a longer
period, the breakeven point would move out even further. For example shifting the
amortization to 20 years results in an additional four years to reach breakeven or a total of
25 years. The proposed amortization schedule also matches the traditional GAAP
treatment for writing off equipment as it becomes obsolete or is no longer used. The
existing meters would amortize out at approximately the same rate that the old meters are
taken out of service. The other advantage of the amortization schedule matching the
implementation schedule will be to provide a partial cash supplement to the heavy
upfront cash requirements of the new AMR system.
The long-tenn savings of an AMR system comes from a reduction of O&M expense.
The first year after the AMR system is fully installed across the Company s service
tenitory (2008), projected O&M for the AMR system is $7.5 million less than the
projected O&M for the current meter system. O&M for each year of the first six years is
shown on the second page of Table 1 below. As the labor and other costs continue to
escalate the gap between the O&M for an AMR system and the current meter process
widens. Of course the additional cost of an AMR system over the Company s current
meter process is in the financing and depreciation revenue requirement. In the first year
after the AMR system is fully installed across the Company s service tenitory, projected
financing costs and depreciation for the AMR system is $8.6 million more than the
projected cost for the current meter system.
Additional details of the Company s analysis are included below and in Appendix C.
The following chart plots the revenue requirement of AMR compared to our current
meter reading process over 40 years. For actual data points see the first table in
Appendix C.
50,000,000
45,000,000
40,000 000
35,000,000
000,000
25,000,000
20,000,000
15,000,000
10,000,000
000,000
CHART 1: Revenue Requirement
-Auto Meters
- - -
Standard Meter:
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This page has been removed because it contains confidential
information.
This page has been removed because it contains confidential
information.
2003 Analysis Assumptions
The 2003 financial analysis was based on the following assumptions:
The analysis covers a 40-year time frame.
The meter count (i., number of customers) increases yearly by our CUITent load
forecast projections.
The operation and maintenance costs (including labor) escalate yearly based on
Idaho Economics' CPI forecast.
CuITent productivity levels remain constant
The present value calculations are based on Idaho Powers after-tax weighted
average cost of capital of 7.241 %.
The book value of the existing manually read meters are amortized over the four-
year implementation schedule in order to defray some of the cost of the
implementation
The AMR system operating costs are based upon reduced staffing levels plus
other related operating costs.
The AMR meters have a 20-year life.
The AMR station equipment has a 15-year life.
The transfonner buss equipment has a 25-year life.
Software and infonnation systems have a 7-year life.
CUITent meters have a 35-year life.
All equipment is replaced at the end of its useful life.
The price of the AMR system is expected to hold finn or decrease.
All meter equipment replacements are at today s cost.
Advanced Features ReQuirin2 Additional Investment
The following advanced features are not included in the "plain vanilla" AMR system
analyzed by the Company. These additional features would require additional
investments and software upgrades in order to be implemented. In order to identify the
potential costs and benefits of these additional features, as well as the specific
functionality and program design which would be desired, separate analyses would need
to be penonned.
Outage detection and restoration verification.
Remote meter connect and disconnect.
Demand management via remote load control.
Providing energy consumption data supporting advanced pricing such as critical
peak TOU pricing and real-time pricing. *
*Note: Before advanced pricing can be attempted, additional investment will be required
to upgrade the existing customer information and billing system. Also, a method for
communicating price signals to customers will be needed. Both of these functionalities
are separate from the AMR system.
Potential Risks
The following risks are associated with making an investment in an AMR system at this
time.
The cost of AMR technologies may decrease in cost as more deployments occur.
The functionality of AMR may increase in the near future
The technology selected for deployment today may become obsolete due to
technological advancements prior to reaching the breakeven point in 21 years.
The limited number of vendors providing AMR technologies and the related
financial stability of vendors.
Both radio and PLC AMR technologies are proprietary; once a specific
product is deployed, future vender competition for material and service is
virtually eliminated, resulting in a single source supplier.
0 If the vendor for the deployed proprietary technology were to change the
technology, discontinue support or service, or go out of business, it could
have a significant impact on the utility.
Cost Recovery of AMR Investment
Idaho Power to proceed with the implementation of an AMR system, Idaho Power would
recommend that standard ratemaking treatment be utilized. This treatment would
include: 1) recognizing in rate base any investment in AMR equipment; 2) making
known and measurable adjustments to rate base for any near tenn investment in AMR
equipment; 3) recognizing any adjustments to O&M expenses; and 4) accelerating the
depreciation on the net book investment in existing meters. In addition, Idaho Power
would suggest that, depending on the timing of rate case proceedings, a separate
proceeding to include in retail rates the costs of additional investment in AMR equipment
as well as the decrease in O&M expenses might be appropriate. Such a proceeding was
conducted in Case No. IPC-95-4 to include in retail rates the Company s investment in
the Twin Falls and Swan Falls plants.
Recommendation
The infonnation contained in this report supports the conclusion that investing in an
AMR system is not a prudent investment at this time. The financial analyses conducted in
2002 and 2003 show that the cost of an AMR system for Idaho Power s customers is not
justifiable based on the savings achieved by eliminating the costs associated with manual
meter reading processes. Idaho Power customers would incur greater costs for the first six
years of the project and would not breakeven until year 2024. This is longer than the life
of many of the components comprising an AMR system. With such a long payback for a
developing technology, one has to question whether the AMR technologies today would
become obsolete before Idaho Power and its customers could realize the financial
benefits.
Idaho Power recommends that the Company and the Commission continue to monitor
developments in the AMR industry and conduct regular assessments to determine the
appropriate time for AMR. Idaho Power believes that there is a future for AMR for our
customers in the next several years. It has been that belief that has prompted the
Company to independently test AMR in Idaho City as well as conduct studies and
compares the costs of AMR with the current metering process. As our meter related
O&M costs increase with inflation and as the cost of this new technology becomes more
affordable, while at the same time increasing in functionality, the time will be right to
take advantage of AMR at Idaho Power and immediately save money for our customers.
APPEND IX A
Technolo2Y Analysis Philosophy
The methodology used to select a specific automated meter reading (AMR) technology
and vendor was consistent with the foBowing philosophy.
The AMR system must provide automatic meter data coBection from aB Idaho
Power Company customers. (Approximately 420 000)
The AMR system vendor must be able to demonstrate that their product is beyond
the development/testing/piloting stages and is in fun-scale operation at other
electric utilities.
Technolo2V ReQuirements
1. The technology must be deployed at over 1 000 000 service points and with at
least 200 000 service points at a single utility company. This requirement
separates multiple pilot locations from fun deployment. It also demonstrates
large-scale integration with biJ1ing systems. Idaho Power does not want to put
customer-biBing processes at risk due to the deployment of an undeveloped
unproven technology.
2. The technology must be applicable to Idaho Power s biJJing requirements by
customer class.
a. Residential
b. Commercial (includes smaB and large commercial and inigation)
3. The technology must be applicable to Idaho Power s customer densities.
4. The technology selected must not be dependent on customer maintaining other
utility services to provide the communication link to Idaho Power. If the AMR
system is dependent on the customer maintaining services , such as telephone
cable, or Internet, the Idaho Power could incur significant cost in obtaining
readings when the customer fails to notify the Company of changes in service
status.
5. The AMR system must include the communication link for the coBection of
customer meter data.
6. The product must be capable of coBecting and transmitting hourly consumption
data to support time of use rates as weB as traditional rates.
7. The AMR system must be capable of two-way communications.
Note: The numbered columns in Table 2 coITespond to the six technology requirements
listed above.
no ogy creemng esu ts
AMR Technology
Telephone Yes Yes
Sate11ite Yes Yes
Pager Yes Yes Yes Yes
Broad Band Power Line Canier Yes Yes Yes
(PLC)
Frequency Modulated PLC Yes Yes Yes Yes Yes
Fixed Network Radio Yes Yes Yes Yes Yes Yes ,Yes
Zero Crossing Modulated PLC Yes Yes Yes Yes Yes "Yes Yes
TABLE 2 AMR T
Based on the evaluation summarized in Table 2 , the fo11owing technologies meet a11 the
technology requirements.
Fixed Network Radio
Zero Crossing Modulated PLC
Vendor ReQuirements
1. The vendor has deployed this technology effectively on a scale of at least 420 000
units within a four-year time frame.
2. The vendor has the capacity to provide product on our timetable.
3. The vendor has a major share of the AMR product market.
Based on the requirements above, it appears that several fixed network radio vendors and
the vendor of the zero crossing modulated power line carrier technology meet all the
requirements.
Technolo2V Cost Comparison
In an effort to evaluate the cost effectiveness of a fixed radio network compared to a
power line canier system, three service tenitory scenarios were developed covering two
types of customer meter installations (residential only and residential plus commercial)
and two types of customer densities (urban and rural). The results of this analysis are
displayed in Tables 3 , and 5. Note: Tables 3 and 4 are provided to depict Non-Idaho
Power service tenitories for cost comparison purposes.
r an -esl en Ja ustomers
Criteria Data Radio PLC
Total Customers 420 000
Service Tenitory Sq. Miles 840
A vg. Customers Per Sq Mi 500
Sub Stations
Residential Customers 420 000
Commercial Customers
*Residential Meter Cost $100 $42 000 000 $42 000 000
*Commercial Meter Cost
*Residential Meter Inst Cost $5.100 000 100 000
*Commercial Meter Inst Cost
*PLC Communication 52 Stations 011,400
*Radio Communication 000 Cells 000 000
*Installation Cost $49 100 000 $47 111,400
TABLE 3 U b R Od f I C 0 I
* Data + or - 10%
The information in Table 3 is provided to depict a typical example of the capital outlay
required to install an AMR system in a "Utility Company" whose service tenitory is
located in an urban area for both the fixed radio network technology or the power line
canier technology. The data supplied does not represent Idaho Power s service tenitory
or customer counts. In this illustration, the costs are comparable for automatically
reading "watt-hour" meters typically used with urban residential customers.
For an AMR system to be beneficial to Idaho Power and it's customers , the installation
would need to also reach Commercial and lITigation customers in order to reduce staff as
these customer would still be required to be manually read.
Criteria Data Radio PLC
Total Customers 420 000
Service Tenitory Sq. Miles 840
A vg. Customers Per Sq Mi 500
Sub Stations
Residential Customers 320 000
Commercial Customers 100,000
*Residential Meter Cost $100 $32 000 000 $32 000 000
*Commercial Meter Cost PLC $350 $35,000 000
*Commercial Meter Cost Radio $290 $29 000 000
*Residential Meter Inst Cost 600 000 600 000
*Commercial Meter Inst Cost $15 $1,500 000 500 000
*PLC Communication 52 Stations 011,400
*Radio Communication 000 Cells $5,000 000
*Installation Cost $69 100 000 $73 111,400
TABLE 4: Urban - Residential & Commercial Customers
*Data + or - 10%
The infonnation in Table 4 is provided to depict an example of the capital outlay required
to insta11 an AMR system in the same urban area with the same technology comparison
but changes the customer mix to include commercial customers. In this iHustration, both
the fixed radio network technology and the power line carrier technology have
comparable costs for automatically reading "watt-hour" meters typica11y used with
residential customers and "demand" meters typically used with commercial customers.
While the customer mix is somewhat representative of Idaho Power, the data supplied
does not represent Idaho Power s rural service territory. Table 5 attempts to reflect the
urban and rural nature of the Company s service territory.
Criteria Data Radio PLC
Total Customers 420 000
**Service Territory Sq. Miles 000
** Actual Customer Locations Sq.053
Miles
** A vg. Customers Per Sq Mi
**Sub Stations 192
Residential Customers 320 000
Commercial Customers 100 000
*Residential Meter Cost $100 $32 000 000 $32 000 000
*Commercial Meter Cost PLC $350 $35 000 000
*Commercial Meter Cost Radio $290 $29 000 000
*Residential Meter Inst Cost $14 $4,480 000 $4,480 000
*Commercial Meter Inst Cost $20 000 000 000 000
**PLC Communication 192 Stations $11 760 000
*Radio Communication 231 Cells $50 577 500
*Insta11ation Cost $118,057 500 $85 240,000
TABLE 5: Urban & Rural- Residential & Commercial Customers
*Data + or - 10%
** IPCa Data
The infonnation in Table 5 attempts to provide more of an Idaho Power Company look
for both the customer makeup and the size of the service territory and the related capital
outlay required to reach a11 of our rural customers. While the actual service territory is
000 square miles, the Company does not have customers in every square mile of the
territory. In fact a our analysis shows that the Company has 5,053 square miles of
customers to serve or an average of 83 customers per square mile.
In this illustration, the capital outlay required to insta11 either a fixed radio network
technology or a power line carrier technology dramatically increase when the rural nature
of our territory is considered. The capital outlay required for fixed radio network
technology is significantly higher by additional $33 miHion dollars over what the power
line carrier technology for automatically reading meters would cost.
The three comparisons above show the costs of both technologies being comparable to
each other in urban areas , but when the customer density drops due to a more rural
environment, such as Idaho Power s service area, then power line carrier technology has
a distinct cost advantage over the fixed radio network.
Idaho Power considered the feasibility of installing a combination AMR system
consisting of a fixed radio network in our urban areas and a power line carner system in
our rural areas. However, there is no obvious cost savings or additional benefits for such
a deployment, but there are some significant operational considerations. For example:
A power line camer system more closely matches our Company s core
competencies and operational processes. Power line construction , operation and
maintenance are Idaho Power Company s technical expertise. We have the
knowledge, experience and equipment capable of maintaining a power line carrier
AMR system.
Additional system benefits may be achieved with a power line carrier system.
Using Idaho Power s distribution network provides communication connectivity
with all of our customers independent of telephone service, radio, or paging
coverage. Also, using the power line as the communication medium allows Idaho
Power Company to monitor the status of more points on our distribution system.
One company-wide AMR technology will minimize meter-related inventories and
streamline the processes associated with customer growth.
Based on the above analysis, Idaho Power selected the zero crossing modulated power
line camer technology as the model for perfonning a financial analysis.
APPEND IX B
Comparisons of Cost Components in 2003 and 2002 Analysis
The 2003 financial analysis is an update of the 2002 financial analysis with the fol1owing
differences.
i erences etween mancla nalyses
2003 2002
O&M Based on 2003 Budget O&M based on 2001 Actual Expenses
Cost of Capital 2002 Year End February 2002 Cost of Capital
CPI Using 2ra QTR 2002 (40 Yr. Avg.CPI 2nd QTR 2001 (40 Yr. Avg. 2.48%)
2.23%)
2002 Income Tax Rates (39.1 %)2001 Income Tax Rates (39.2%)
2002 Property Tax Rates 2001 Property Tax Rates
2002 Insurance Rates 2001 Insurance Rates
Meter Growth Based on Feb 2003 Meter Growth Based 2001 Customer
Customer Growth Forecast Growth Forecast
4 Year Implementation Strategy - Staged No Implementation Strategy -
Capital Expenditures Implementation Timing Ignored
O&M Savings Based on 4 Year Staged O&M Savings Assumed Immediately
Implementation
Included Employee Transition Costs No Employee Transition Costs
Included Savings of 5 CSR Positions No Savings From CSR Positions
Old Meters Amortized Over 4 Years Old Meters Stay in Rate Base
Added Low Density Areas Excluded Low Density Areas
Increased Station Equipment to Handle Basic Station Equipment to Handle
Daily Collection of Hourly Meter Monthly Col1ection of Monthly Meter
Readings Readings
Included Additional Data Storage to No Additional Data Storage Costs
Handle Hourly Meter Readings Included
ABLE 6 D n 2003 d 2002 Fo 0 I A
APPEND IX C
The pages in this Appendix C have been removed because they
contain confidential information.