20021206DRAM Comments.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
TlME-OF-USE PRICING FOR IDAHO
POWER RESIDENTIAL CUSTOMERS.
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Comments of the Demand Response and Advanced Metering Coalition (D~~ 0'\
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The Demand Response and Advanced Metering Coalition (DRAM)! is a policy (E) ~ DJ.
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organization comprised of utilities, public interest groups, metering and communications
companies and demand response providers. DRAM's interest is in providing input and
infonnation to parties that are examining or implementing demand response programs
particularly those focused on the mass market customer. We appreciate the opportunity
to provide comments to the Commission and other interested parties in Idaho and hope
that they will be of assistance relative to the subject proceeding.
Introduction
Given the potential benefits from demand response that have been demonstrated and
estimated by many experts, and in particular those stemming from the option of dynamic
pricing, it is prudent at the present time for all state regulators to be examining the level
of benefits, as well as how to capture them, in their specific state. Therefore, DRAM
believes the Commission is acting appropriately at this time to explore time-based pricing
1 DRAM members participating in these comments include: eMeter, SchlumbergerSema, Landis + Gyr,
MeterSmart, DCSI/TW ACS, Echelon, Puget Sound Energy and the Alliance to Save Energy. More
information on DRAM can be found at www.dramcoalition.org.
in the present proceeding. DRAM also concurs, however, with the statement of Idaho
Power Company (IPC), as expressed in their motion of October 4, 2002 , that there are a
myriad" of issues to be considered in moving forward with such pricing programs.
its review of the Commission s order and IPC's report pursuant to such, DRAM finds
that many of the necessary issues have been raised but that in some cases insufficient or
possible inaccurate infonnation is provided on them. DRAM also finds that some issues
may not have been introduced at all in this proceeding to date. DRAM therefore
respectfully submits its comments in an attempt to highlight these issues and provide an
additional viewpoint for the Commission and other affected parties in Idaho to consider
as they move forward in this proceeding.
Background
It is assumed that there is agreement among the Commission and the parties that a valid
objective for utilities and providers is for customers to better understand their electricity
usage so as to take steps to manage their usage and reduce their bill. The present system
of rates and tariffs runs counter to such an objective in that customers are unable to see
any link between the cost they pay for electricity and the time-dependent cost to produce
and deliver that electricity. It is further assumed that the parties would agree that
providing customers with choices in the way they buy electricity is something that
customers would like to have, but would also agree that such choices come not only from
deregulation and introduction of a choice of competitive supplier but by providing
different options from the existing provider. Yet another point of agreement would be on
2 Idaho Power Company s Motion For Additional Time to File Reply Comments, Page 2
the fact that, as is pointed out in the IPC/Christensen Report, customers have repeatedly
shown a willingness to respond to price signals.
Providing customers with time-based pricing options addresses each of the above
objectives and areas of agreement. It can also address a number of other mutual and
respective objectives of customers, regulators and utilities, including control of market
power, optimization of system planning and expansion and reduction in utility
operational costs.
Therefore the question is not whether dynamic pricing is a good idea; there appears to be
agreement that it is. The question is instead whether the costs and benefits from it allow
the initiation of such pricing in a particular situation or case. To properly address this
question in a specific instance, it is necessary to not deal only with the cost and benefits
directly attributable to customers and UPC from the pricing program being in place and
in operation. It is also necessary to identify and factor in any additional benefits and
costs which may be indirect or which accrue from the deployment of enabling technology
put in place to allow the pricing program.
Indeed, an evaluation of dynamic pricing and other mass market demand response
options becomes necessarily intertwined with an evaluation of the necessary enabling
technology, with in most cases each becoming a driver for the other in synergistic
fashion. It is also important to conduct the evaluation, as the Christensen report implies
3 Overview of Residential Time-of-Use Pricing - Problems and Potential, Christensen Associates, July 15
2002, Pages 11-
so as to not to focus only on Time-of-Use Rates but on dynamic pricing as an area of DR
which provides several different options ranging from Real Time Pricing to Critical Peak
Day Pricing. In this regard, the Commission needs to consider whether the right question
has been asked in the proceeding to date, i.e. should TOU rates be initiated or whether the
question should be focused on all dynamic pricing options.
Types of Meters
The IPC Viability Study filed with the commission states that IPC does not
presently have metering equipment in place to record usage by time period for residential
customers and then proceeds to describe two options which could be utilized: "standard"
time-of-use meters or an automated meter reading system.
DRAM would submit that the key to addressing metering choices is
understanding the objectives being pursued and also the benefits, particularly indirect
benefits, that each choice provides.
Standard time-of-use meters, as described, provide only one new specific new
benefit. They enable time-of-use rates due to their ability to record usage in a specific
pre-set period for billing purposes. Depending on the meter, however, this may simply
be an accumulation of data in several time-based registers and not include data collection
in hourly intervals. Under this scenario, the utility is provided with no new data, no new
4 Residential Time-of-Use Pricing Viability Study - Report to the Idaho Public Utilities Commission, Idaho
Power Company, September 12 2002, page 32.
meter reading capabilities, and no new operational abilities. The customer receives no
new benefit in tenus of more frequent data access or presentation. Neither the customer
nor the utility can benefit from changes to the TOU period because to change the periods
would be a manual action. Also, this means that among the dynamic pricing options
under the heading of demand response, only simple TOU rates can be implemented.
Other options such as Critical Peak Day Pricing cannot be.
An automated meter reading (AMR) metering system, per say, does not enable
TOU pricing/rates. The functional objective of AMR is to automate and streamline the
meter reading operation so as to reduce meter reading costs. An AMR system does not
necessarily provide the interval measurement necessary for dynamic pricing and, in most
cases, a basic AMR system does not increase the frequency of data access and
presentation to the utility or the customer. Monthly reads is still the nonn.
Communication with these basic systems is typically one-way to a mobile receiver (a
van).
Important to note, however is that with either a standard or advanced AMR
system, the benefit to a utility whose existing meters are of the older, conventional, non-
AMR type can be great. Several utilities in recent years have undertaken AMR
deployments based on a business case supported by savings in meter reading operations.
The type of meters most closely associated with demand response is referred to as
advanced meters. These meters provide automated meter reading functionality but do
by way of a fixed communications network which provides flexible two-way
communications capability. These meters are defined by having the ability to deal with
data according to several parameters:
Recording and measurement of data on at least an hourly interval basis
Retrieval by/Transmittal to the utility on at least a daily basis
Customer access to usage data on at least a daily basis (via a free website)
Provision of interval based usage and pricing data to customers on at least
a monthly basis (via the monthly bill).
These advanced meters provide the most benefits to customers , the providing utility, and
to regional operating entities among the three meter types discussed above.
Costs of Meters
The IPC Viability Study indicates in numerous instances that the "high" cost of
metering makes TOU/dynamic pricing prohibitive from a cost effectiveness standpoint.
The cost data for use in detennining cost effectiveness are found on page 32 of the report.
The average meter cost per customer for a standard time-of-use
meter is said to be $145 , with the total cost being approximately
$47 million for deployment to IPC's approximately 300 000
customers.
incremental cost of the TOU meter compared to the standard meter
now installed for residential customers would result in an increased
charge to customers of about $1 a month.
The latest cost estimate to install an AMR system across Idaho
Power s service territory is approximately $72 million.
Absent any other data being presented, DRAM offers the following
questions/comments:
It is unclear if the average of $145 is an average of all customer
types or only residential customers. DRAM presumes the latter
but, if so, would submit that an average cost of $1 00 is more
appropriate for an advanced meter capable of allowing TOU
pncmg.
It is unclear what incremental costs are being considered in the
estimation of the $1 per month charge. It is also unclear over what
period the $1 charge would be in effect.
It is unclear whether the $72 million cited is this incremental cost
and, in either case, what the cost consists of, i.e. different meters
additional system costs, etc.
The main cost differential between the standard TOU meters described in the IPC
Viability Study and AMR or Advanced Meters is the cost of the communications system
deployed. DRAM presents Table 1 as its understanding of current costs for the three
metering types discussed above.
Table 1
Cost of Metering Technology
Non Communicating Non
Customer Communicating
Communicating AMR Communicating
Type Advanced
Conventional TOU MeterMeter Meter
Meter (standard)
Mass market meter $25 $75-100(single phase)
Module to retrofit
used mass market $45-100 $45-
meter
Mass market meter
Metering Costs with communications $50-100 $50-100
built-
Large commercial $175-300 $175-600meter (polyphase)
Large commercial
meter with $300-000 $300-000
communications
Mass market meter
scattered $50-100
deployment
Mass market meter
Meter saturation $5-
Installation deployment
Costs Large commercial
meter, scattered $150-250
deployment
Large commercial
meter, saturation $50-100
deployment
Communications (includes installation)$10-100Network Costs
Total Metering &Mass market $75-125 $52-200 $125-200 $70-225
Communications Large commercial $225-400 $350-000 $225-700 $350-250
5 Network costs vary according to volume. Cost range shown is for a minimum deployment of 50 000
points.
Based on a cost estimate of $1 00 per customer, which may be at the high end of the
applicable cost range, the total cost for providing advanced metering to all 300 000 of
IPC's residential customers would be approximately $30 million. This estimate is based
on commercially available technologies installed on millions of customers in the U.
While this estimate could conceivably rise due to special circumstances present in the
IPC service territory, DRAM still believes that the estimate of $72 million for an AMR
system as presented in the report is substantially too high.
Benefits
One of the challenges of demand response options is to identify the costs and benefits
attributable to DR efforts.Accounting for all of the benefits may be by far the more
difficult task of the two.
In its report for IPC, Christensen focuses on the costs and benefits of shifts by customers
in usage and prices paid, as well as revenue gained or lost by the utility. The study also
appears to address the benefits to non-participants and the system overall from dynamic
pricing s effect on wholesale prices and the market power of wholesale prices. It is less
clear as to whether the positive externalities that accrue to the region from an IPC
program are accounted for; it does not appear as though they have been
DRAM does not present questions as to the modeling and analysis related to these
benefits (and costs, in the case of the potential revenue impacts upon the utility).
However, DRAM does believe that other benefits of a dynamic pricing program are not
addressed in the report, and suggests that these warrant further examination by the
Commission should it decide to continue its exploratory effort. These include:
Benefits of Advanced Metering in Unrelated to Dynamic Pricing
Distribution company benefits resulting from advanced metering with two-way,
fixed network, automated communications.
The introduction of an automated meter reading system as a replacement for a
system of older, conventional meters couple with manual meter reading can lead
to dramatic benefits to a distribution company. When deployed via a two-way
fixed communications network, distribution operations personnel find themselves
with new data, new functionality, lower costs and a number of other advantages.
These include:
Outage Management/Response
Trip avoidance
Crew Optimization
Customer Care
More timely and efficient response to customers
Reduced Meter Reading Costs
Reduced labor costs
Avoided vehicle and equipment costs
Improved Meter Reading Accuracy
Reduction in estimated bills
Two-way communications ability and interactive messaging ability
Load control and management capabilities
Acquisition of new and different data
Improved forecasting
Distribution system optimization
Distribution system planning and expansion
individual customer benefits
enhanced usage infonnation - resulting in enhanced ability to practice
energy management
additional rate options (customer choice of different product from same
provider)
system benefits
faster wholesale power cost settlements
improved data
improved forecasting
system optimization
system planning and expansion
Summary
DRAM commends the Commission and other parties in Idaho for their initiative in
exploring dynamic pricing for mass market customers. We believe that the proceeding
to date has been a good start in identifying the cost and benefits of dynamic pricing but
yet we also believe the costs of the enabling technology, in this case advanced metering,
may have been overestimated and that some of the benefits from deployment of advanced
metering may not have been accounted for. DRAM would be happy to provide more
detailed infonnation on any of these issues.
Respectfully submitted this 6th day of December, 2002
Dan Delurey
Dan Delurey
Executive Director
Dan Delurey
Executive Director
Demand Response and Advanced Metering Coalition (DRAM)
O. Box 33957
Washington, DC 20033
Telephone: [phone]
Email: dan.delurey~dramcoalition.org