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IDAHO POWER COMPANY
PO BOX 70
BOISE, IDAHO 83707
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An IDACORP Company
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Director, Pricing
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[phone]
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mbrilz (ij) idahopower .com
MAGGIE BRILZ
January 30, 2003
Ms. Jean D. Jewell , Secretary
Idaho Public Utilities Commission
P. O. Box 83720
Boise,ID 83720-0074
RE:Annual DSM Report
iA E -tJ.2- J.) Dear Ms. Jewell:
Please find enclosed an original and seven (7) copies of Idaho Power
Company s Annual DSM Report as required by Order No. 29026.
1 would appreciate it if you would return a stamped copy of this transmittal
letter for our files.
Sincerely,
m~ A5~
Maggie Brilz
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Enclosures
Ric Gale
Bill Eddie
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Annual
Demand Side Management
Report
January 30, 2003
2002 DSM Tariff Rider Report
In Order No. 29026, the Idaho Public Utilities Commission (IPUC) directed Idaho
Power to "file an annual written report to the Commission detailing: the Advisory
Group s recommendations, the Company s response to those recommendations, the
associated program costs, the DSM accounting numbers, customer response data and
information on new DSM opportunities This report reviews those issues in three
sections. Section I addresses program description, costs and customer response as well as
the Advisory Group s recommendations for that program and Idaho Power s response.
Section IT reviews the rider funding and expenses and Section III provides information on
Idaho Power s efforts to look at new DSM opportunities.
I. Program details, Advisory Group recommendations and the Company s response
to those recommendations
Since the formation of the Energy Efficiency Advisory Group (EEAG) in spring,
2002 , the group has met five times. The results of the first meeting, which was held on
April 30 , 2002, were reported to the Idaho Public Utilities Commission (IPUC) in a
report filed May 2, 2002. Subsequent meetings were held July 11th, September 5t
November 14th and January 9th, 2003.
The EEAG consists of 13 customer state agency and special interest
representatives and two representatives from Idaho Power. Meeting minutes and other
meeting materials are provided to all EEAG members, including IPUC staff, and are
available upon request.
As of January 2003 the EEAG has recommended implementing three specific
customer DSM programs that have a combined total estimated budget of $1 710 000.
These programs and the timeframe for their implementation are:
School Operator Training
Budget
$850 000
$50 000
TimeframeProgram
Lighting Coupon Program September 2002 - April 2003
November 2002 - December 2002
Page 1
Air Conditioner Cycling
Pilot Program $810 000 March 2003 - December 2004
The major activity for the Lighting Coupon Program was conducted during the
fall, 2002; however, several aspects of the Program will continue until April, 2003.The
classroom component of the School Operator Training Program was implemented in
November, 2002. Idaho Power filed an application with the Commission on December
, 2002 , requesting approval to implement the Air Conditioner Cycling Program (Case
No. IPC-02-13).
Lighting Coupon Program
Program description
Starting October 1 ih , Idaho Power sent a brochure and two $3 coupons
359 465 residential and small commercial customers. These coupons could be used
toward the purchase of Energy Star labeled compact fluorescent light (CFL) bulbs from
participating retail stores. Ecos Consulting was hired to coordinate coupon redemption
and to work with the participating retail stores.
Idaho Power staged a fairly aggressive public relations campaign designed to
educate our customers about the characteristics of CFL bulbs and to let our customers
know of the coupon availability. Prior to the coupon mail-out
, "
ticklers" were inserted in
customer bills, articles were printed in the Consumer Connection and messages were
printed on the bill envelopes. Through these various means of communication, the
Company attempted to alert customers to the presence of the coupons in their bills so
they would not throw them away or destroy them.
The program campaign kicked off with an announcement during the Alexander
House Energy Star Open House with Governor Kempthorne on August 20 , 2002. During
October and early November Idaho Power sponsored three launch events at community
shelters to help upgrade the lighting in the facilities and provide a forum for local news
coverage. Launches were held at the Ike Kissler Safe House in Twin Falls, the Bannock
House in Pocatello and at City Light Home For Women and Children in Boise. Radio
ads were placed starting mid-October through mid-December and print ads were placed
Page 2
in 18 newspapers across the service territory. Idaho Power was able to place two large
educational information articles in the Idaho Statesman discussing bulb selection
placement, characteristics and disposal, and all print ads had an educational message.
Idaho Power worked with retail stores across the service territory to sell Energy
Star CFLs and accept the coupons. Customers could look up information about the
program on the Idaho Power web site and locate participating retail stores near them. In
addition, there was a toll free phone number available for customers to use for assistance
in locating participating retail stores. During the campaign, program field personnel
manned information booths at stores to answer questions and promote the program.
These booths were a successful way to understand customer concerns and promote sales.
Idaho Power offered co-op advertising to retail stores to promote the program and several
stores ran their own ads.
Idaho Power distributed extra coupons to customers who called our Customer
Service Center and requested extra coupons. Meter readers and linemen handed out
coupons to customers they encountered during their workday. Coupons were included in
high bill packets, and extra coupons were delivered to senior centers and community
centers. The coupons expired December 31 2002.
Savings estimates are based on regional evaluations and indicate an annual
reduction of 67.5 kWh per bulb when compared to an equivalent incandescent bulb.
Program costs and customer response
Preliminary results as of January 15, 2003, show over 32 000 coupons redeemed.
The budget for this program is $850 000. Actual expenditures to date are approximately
$321 471. Final participation numbers for the coupon program will be available in
February 2003 , but appear to be well below the desired target penetration of 15% (or
108 000 coupons).
considered.
Therefore, a second phase of promotions is currently being
Program numbers thus far show that of the coupons redeemed, 9% were redeemed
by small commercial customers and 91 % were redeemed by residential customers. This
breakdown is roughly the same ratio of those mailed out and indicates that both
residential and small commercial customers redeemed the bulbs at roughly the same rate.
Page 3
Over 128 retail stores that sold lighting products signed up to be participating
retailers. The vast majority of coupons were redeemed at larger corporate stores that
don t break down redemption rates by region. However, for the smaller retail stores there
is data that show excellent participation across the service territory. For example
customers in the western part of the service territory submitted 20% of the coupons
redeemed at smaller retail stores; customers in the southern area, 26%; customers in the
eastern area, 22%; and customers in the central Boise area redeemed 32% ofthe coupons
redeemed a small retail stores.
Energy Efficiency Advisory Group recommendations
Idaho Power presented the proposal for a Coupon Lighting Program to the EEAG
during the July 11 th meeting. Idaho Power received the following recommendations.
The general consensus of the EEAG was that Idaho Power should
implement the CFL program
Idaho Power initiated implementation of the program
The EEAG suggested that the program be offered to both residential and
small commercial customers
Idaho Power included small commercial customers in program
The EEAG wanted Idaho Power to track the small commercial
participation. Tracking of the small commercial participation would assist
in the allocation of program costs to each sector.
Coupons were coded so that the redemption by each customer
group could be tallied
The EEAG suggested a marketing and education component be included
as part of the program.
Idaho Power included an extensive marketing and education plan
in the program implementation
The EEAG was evenly split between offering customers 1 coupon with a
face value of $4, or 2 coupons with a face value of $3.
Page 4
Idaho Power choose to offer 2 $3 coupons because of the potential
for this design to provide more energy savings and increased cost-
effectiveness
The suggestion was also made to provide a means of delivering CFLs to
lower income customers.
Idaho Power added a component to the program that distributed
CFL bulbs free of charge to low-income customers through the
Community Action Agencies ' Low Income Weather Assistance
(LIWA) program.
Additionally, there was some concern expressed by the EEAG that there
might be a large number of people who have already purchased CFL
bulbs.
In response to this concern, Idaho Power commissioned a short
telephone survey, fielded in August, that indicated 61% of Idaho
Power customers had purchased CFLs in the past 12 months. This
finding was shared with the EEAG during the September 5th
meeting and after discussing the issue, the EEA still felt Idaho
Power should proceed with the program.
Next steps
Idaho Power is pursuing a second phase of the CFL program with other kinds of
program promotions. The objective is to leverage the high awareness of the program
established in the first phase with lower-cost promotions to increase penetration and
reduce overall program cost per bulb.
School Building Operator Training
Program description
In order to help school districts manage their energy costs, and in recognition that
a key to energy savings is a well trained operations and maintenance staff, Idaho Power
joined with Idaho Department of Water Resources, Energy Division and the Northwest
Building Operators Association (NWBOA), to offer technical operator training.
Page 5
NWBOA has a five-day level one training that has been supported and evaluated by the
Northwest Energy Efficiency Alliance. A letter of invitation was sent to all K-12 school
districts in the Idaho Power service territory. Training was scheduled for November 13-
15 and November 20-, 2002. The training was included as part of the annual Idaho
Energy Conference so that participants could attend the sessions and activities with other
people who are focusing on energy efficiency. The cost of the program included operator
training ($400 per participant), conference registration and meals and lodging for out-of-
town attendees. In addition, attendees received a year membership in NWBOA and, if
they passed the course tests, were awarded a certification.
Because this program was exclusively education and training, there are no
specific installed measures for saving electricity. However, the Northwest Energy
Efficiency Alliance conducted an evaluation of the NWBOA training several years ago
and found that on average attendees save 55 000 kWh per year by applying the lessons
learned in this training.
Program costs and customer response
Thirty school building operators from throughout Idaho Power s service territory
attended the training and most were awarded Level I certification at the Idaho Energy
Conference. There was excellent representation from small and large schools and there
was broad geographic representation. The budget for this program was $50 000;
$33 538.52 has been expended to date, with $10 000 set aside for further development.
Energy Efficiency Advisory Group recommendations
On September 5th, Idaho Power presented to the EEAG the proposal for the K-
building operator training program and received the following recommendations.
Strong support was expressed from the EEAG for sponsoring the training.
Idaho Power initiated this program
The EEAG suggested that a survey be conducted with the participants
after the training to determine if changes to building operations are made
as a result of the training.
Page 6
Idaho Power plans to conduct a survey of participants in the first
quarter of 2003.
The EEAG supported paYIng hotel and meal costs for out-of-area
attendees in order to encourage participation by building operators that
would need to travel.
Funding was provided for lodging and meal expenses for this
training
Next steps
A survey of attendees is planned for the first quarter of 2003. This survey will
ask participants what activities and measures they implemented because of the
information provided in the workshops.
Idaho Power would like to make this training information available to school
districts that were not able to attend the training. Therefore, Idaho Power has set aside
$10 000 to work with NWBOA to provide the training and certification process in a
distant learning setting. NWBOA is currently developing a CD that contains the material
provided in the Level I training. It is anticipated that Idaho Power will sponsor a number
of operators to test this training method.
Residential Air Conditioner Cycling Pilot Program
Program description
On November 14t\ Idaho Power presented a proposal for a Residential Air
Conditioner Cycling Pilot Program. In the program, Idaho Power will install, free of
charge, an intelligent programmable thermostat in participants homes. The Company
will then be able to send a signal to the thermostat to cycle the air conditioner off when
resources are needed for peak load reduction. The pilot will target 200 participants the
first year and 300 participants in the second year. All participation is voluntary. This
program will be offered to residential homeowners in Boise and Meridian who have
central air conditioning.
Page 7
Energy Efficiency Advisory Group recommendations
Group discussion centered around three areas of the proposed program design: 1)
the ability to "opt out" of a cycling event; 2) the need for an incentive to participate in the
program in addition to the free programmable thermostat, and 3) the number of days in a
month and hours in a day that cycling may occur.
The EEAG suggested that some provision allowing customers to "opt out"
of the program, especially in emergency situations, was necessary.
Idaho Power is allowing participants to II opt-out with
notification by pm of the day prior to the day they wish to opt
out. This notification time is needed in order to pre-schedule this
resource into our overall resource mix.
The group also suggested that some incentive in addition to the
programmable thermostat would be necessary in order to entice customers
to participate.The potential to start with a small incentive and then
increase it if necessary was discussed.
Along with the incentive of a new programmable thermostat, a
$5/month incentive was added for program participants for the
three months per year of program operation
It was also suggested by the EEAG that any incentive paid to participants
be paid only after the customer had completed participation in the program
for the duration of the program.
Idaho Power examined whether this was possible and decided not
to structure the incentive in this way.Because of the
characteristics of the Idaho Power billing system it is necessary to
credit the incentive on a monthly basis.
Several members expressed the sentiment that in order to help customers
feel comfortable about joining in the pilot program, some description of
when the cycling might occur was necessary.
Idaho Power will provide this information during the participation
solicitation process.
Page 8
The EEAG in general felt that the number of days and hours per day that
cycling could occur could be expanded from the proposed ten days and
four hours per day without decreasing interest in the program.
The hours of the day that the program can operate was expanded
to include the eight hours between pm and 9pm.
The EEAG was asked if they supported Idaho Power pursuing this
program and there was unanimous endorsement.
Based upon the support of the EEAG, Idaho Power pursued the
implementation of this program.
DSM Small Projects and Education Fund Proposal
Description
During the January 9, 2003 EEAG meeting, Idaho Power proposed that starting
January 1 , 2003 , two set-aside funds be established. One fund will provide a small
amount of money for very small project requests and a second fund will provide a similar
amount for education efforts. The amount of money set aside each year for each fund is
2% of the total annual DSM tariff rider funding.
Energy Efficiency Advisory Group recommendations
The EEAG endorsed the proposal to create the two set-aside funds. A
small amount of discretionary funds will allow Idaho Power to respond to
small requests in a timely manner.
In accordance with the EEA discussions, Idaho Power has
established these funds
The EEAG did not want these small project and education funds to be
viewed as "secret" funds and suggested that Idaho Power let customers
know of their availability in some way.
Idaho Power is exploring ways to put notification of the
availability of these funds on the Idaho Power web site
In addition, the EEAG desired that all customer segments have access to
the funds.
Page 9
Idaho Power will monitor the allocation of these funds to ensure
all customer sectors have access
, The activities funded by these set-aside funds will be reported to the EEAG at the
regular meetings.
DSM Comprehensive Study
Description
As directed by Order No. 29026, Idaho Power consulted with the EEAG
regarding the need to initiate a comprehensive DSM assessment study. Because Idaho
Power s primary resource need in the near future is for summer peak reduction and
because most of the regional data available does not address summer demand reduction
DSM options , Idaho Power suggested that if a study were undertaken, it should focus on
residential and commercial summer demand reduction potential on Idaho Power
system. Various study design options were discussed. It was suggested that the cost for a
comprehensive study could range from $100 000 to $150 000.
Energy Efficiency Advisory Group recommendations
A suggestion was made by the EEAG to have Idaho Power come forward
with a specific recommendation for a study that would provide the most
value, present the recommendation to the EEAG, and then gather input
specific to the recommendation.
Idaho Power evaluated options and presented a study design to
group
The group generally supported an abbreviated study, although there was
some support for a larger study.
Idaho Power proposed a study limited to identifYing summer peak
demand reduction programs
The suggestion was made to expand the list of potential RFP recipients.
Idaho Power added some suggested consultants to the list
consultants to receive the RFP
Page 10
Idaho Power has a final draft of the RFP incorporating suggestions by the EEAG.
Residential Time-of-Use Pricing
Prior to submitting its Residential Time-of-Use Pricing Viability Study (Study) to
the Commission on September 12 , 2002, Idaho Power solicited input on time-of-use
pricing for residential customers from the EEAG. A copy of the Company s Study is
attached as Attachment 1.
DSM Screening Criteria
Description
During the January 9, 2003 EEAG meeting, Idaho Power proposed the following
set of screening criteria for use in selecting DSM programs funded by the tariff rider.
First, programs will be cost-effective. From a total resource perspective
estimated program benefits must be greater than estimated program costs. As shown by
the last Integrated Resource Plan, programs that decrease summer peak demand will be
valuable because they reduce the need for peak resources. Programs that capture cost-
effective, lost-opportunity DSM resources will be encouraged.
Second, programs will be customer-focused. From the participants' perspective
programs will offer real benefits and value to customers.
Third, programs will be as close to earnings-neutral as possible. From the
utility's perspective, programs will be selected to minimize the negative impact on
shareowners.
Energy Efficiency Advisory Group recommendations
The EEAG generally endorsed the overall screening criteria proposed by
Idaho Power.
The EEAG suggested adding another criteria to ensure that there is equity
between customer sectors when it comes to spending rider funds and that
attention paid to equity within a sector.
Page 11
Idaho Power added a fourth criterion: Programs will be equitably
distributed, From the customer s perspective, programs will be
selected to benefit all groups of customers. Over time, programs
will be offered to customers in all sectors and in all regions of the
Company s service territory.
The EEAG felt there should be flexibility when project eligibility is
determined. For example, there is support for funding of instruments for
measuring electricity use in the industrial and commercial sectors.
Idaho Power will try to build flexibility into the screening process
The EEAG suggested looking for ways to leverage the funds, like initially
offering rebates at only 10% of project costs instead of starting at 50%.
Idaho Power is pleased with the overall process and finds value in the
recommendations and feedback received by the group.
II, Rider funding and expenses
2002 DSM tariff funding 592 049
Expenditures
EEAG meeting costs
Lighting Coupon Program
School Building Operator Training
* Includes January 2003 expenditures
$ 1 825
$ 321 471 *
$ 33 539 *
III. New DSM opportunities
The primary work in 2002 was forming the Energy Efficiency Advisory
Group and implementing the first set of programs. Now Idaho Power, along with input
from the EEAG, is establishing a long-term look at the DSM activities. The first step in
this process has been completed with the development of the high-level program
screening criteria. These criteria will be used in selecting new programs funded through
the DSM tariff rider. The Company is now establishing the process to apply the
screening criteria to specific program options.
Page 12
In addition, Idaho Power has two efforts that are in the process of examining new
DSM opportunities. It is anticipated that the DSM study reviewed earlier will provide
suggestions for programs appropriate to Idaho Power s system that will reduce demand
during the summer peak load. Since this is a specialized study and since there is no solid
regional data to draw from, Idaho Power plans to hire a contractor to complete this study.
The study has not been awarded at this time.
On a parallel path, where there is information and data available, Idaho Power is
compiling a list of program options in the service territory. This list includes developing
local delivery options of market transformation programs offered by the Northwest
Energy Efficiency Alliance. It also includes irrigation and industrial program options
developed with internal staff.
Page 13
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Residential Time-at-Use Pricing
Viability Study
Report to the
Idaho Public Utilities Commission
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An IDACORP company September 12 , 2002
BACKGROUND
In Order No. 28894 the Idaho Public Utilities Commission (lithe Commission
directed Idaho Power Company (lithe Company ) and the Energy Efficiency
Advisory Group ("the EEAG") to consider implementing a time-of-use metering pilot
program. In Order No. 29026 the Commission reaffirmed its directive that Idaho
Power and the Energy Efficiency Advisory Group "evaluate and report to the
Commission on the viability of a Time-of-Use residential metering program by
September 12, 2002"
To assist in evaluating the feasibility of residential time-of-use (TOU) pricing,
Idaho Power engaged the services of Christensen Associates. Christensen
Associates is an economic consulting firm that has been providing consulting
services to the energy industry for more than 25 years and is well known in the
industry for its work with time-of-use and real-time pricing and market-based
interruptible load programs.
This report is comprised of the following sections:
An overview of residential time-of-use pricing provided by Christensen
Associates
An analysis performed by Christensen Associates assessing the potential
benefits of residential time-of-use pricing for Idaho Power
Issues relating to the implementation of time-of-use pricing which are
specific to Idaho Power
Input from the Energy Efficiency Advisory Group
Conclusions on the viability of residential time-of-use pricing at this time
Christensen Associates Overview
An Overview ot Residential Time-ot-Use Pricing -
Problems and Potential
Steven Braithwait
Christensen Associates
July 15, 2002
The Idaho Public Utility Commission has asked Idaho Power to investigate the
viability of time-of-use (TaU) pricing for its residential customers. This
memorandum serves as the first step in assisting Idaho Power to conduct that
assessment. It provides an overview of residential TaU pricing, including the
following topics:
an historical perspective
a discussion of potential problems that can limit the benefits of residential
TaU to utilities
a description of new types of TaU pricing that show promise in addressing
some of those problems , and
a summary of evidence on customer price responsiveness.
1. Background and historical perspective
The issue of market design , and the current disconnect between wholesale and
retail power markets, has been the focus of intense discussion in recent months. It
has been generally acknowledged that hourly wholesale power costs vary
substantially across hours , days and seasons , while most customers face fixed
retail prices. Thus, customers have no incentive to cut back usage during periods
of high wholesale costs , which would provide needed relief from wholesale price
pressures. As a result, various demand response mechanisms have been
suggested to remedy this problem. One category of demand response
mechanisms is dynamic pricing, in which customers face retail prices that directly
reflect conditions in the wholesale market. The most common example of dynamic
pricing is real-time pricing (RTP) for large commercial and industrial customers.
However, interest in the general topic has renewed discussion of the potential value
of TaU pricing for residential customers.
TaU pricing has been studied in some detail, in a variety of pilot and permanent
programs, over the past twenty-five years, but has never achieved widespread use
for small customers. Over that time, utility rate designers , regulators, academics
and consultants have debated the fundamental principles of retail electricity rate
designs. Traditional utility rate design has focused largely on recovering allowed
costs, and on methods for allocating those costs fairly across various customer
types. A relatively low priority has been given to establishing prices that reflect
differences in the incremental, or marginal cost of generating and delivering
electricity in different time periods.
The principal argument in favor of TaU pricing has always been economic
efficiency TaU prices reflect differences in the average cost of generating
and delivering power during particular time periods, thus providing more appropriate
price signals to customers than do flat rates. Customers can achieve benefits
under TaU pricing if they can shift sufficient consumption from peak-period hours
in which the price exceeds the standard flat price, to lower-price off-peak hours.
Utilities can realize net gains from those same load shifts by avoiding some peak
period sales whose cost exce~ds the revenue generated , and selling more during
low-cost off-peak periods. However, these TaU benefits must be traded off against
higher metering and administrative costs.
Estimates of that benefit-cost tradeoff have fjenerally not been favorable. Two main
factors have weighed against the benefits of Tau pricing for residential customers.
First , TaU prices do not reflect the variability of wholesale power costs with
sufficient accuracy. For example , peak period prices (e.12/kWh) are generally
designed to represent an average across expected wholesale costs during peak-
period hours in a given season (e.summer).1 However, wholesale power costs
can range widely from moderate to very-high levels , depending on actual load
levels and supply conditions. In many hours , TaU peak period prices substantially
exceed the actual cost of power (e.a TaU price of $.12/kWh versus a wholesale
cost of $.04 to $.06/kWh). However, in the very hours in which costs reach their
highest levels , the peak period price is likely to fall far short of that level (e.
12/kWh versus costs of $1.00/kWh or more). Thus, while TaU prices do a better
job than a flat price of reflecting cost differences on average, the price signal is still
not very accurate. When TaU customer reduce load during those peak hours in
which costs are actually low, utilities' revenue can be reduced by more than their
costs.
Second , the relatively low usage level of residential customers, combined with the
first factor of inaccurate prices , limits the overall magnitude of potential benefits
from customer response to TaU prices. These benefits must be traded off against
the additional cost of metering and billing.
Tau rates have generally not been mandated , or established as the default tariff for
residential customers. Most TaU programs have been offered as voluntary
programs, typically targeted at customers with high usage levels , or ownership of
major appliances such as central air conditioning or pool pumps. As a result, most
residential TaU tariffs have relatively few customers.
Two recent programs promoted by Puget Sound Energy (PSE) in Washington
State , and Gulf Power in Florida , provide indications of potential renewed interest in
I To cover expected costs, TaU prices actually need to reflect a load-weighted average of hourly wholesale
costs, where the weights represent the load pattern of the customers expected to take service under the rate.
residential TOU. PSE has undertaken an ambitious program to install advanced
interval meters for all of its residential customers, along with software and
communication devices that give customers the ability to monitor their energy
usage and PSE's wholesale power costs online. PSE has assigned all customers
with the new meters to a TOU rate , although customers have the right to opt out
and return to a flat rate. PSE claims that a large share of the cost of the metering
and communications system may be covered by improved meter reading and billing
efficiency, even before accounting for the benefits associated with customer load
response to TOU prices. PSE has also discussed a range of potential advanced
pricing approaches that they may consider offering to take advantage of the
metering and communications capabilities.
Gulf Power has recently announced a planned expansion of their pilot. Residential
Service Variable Price (RSVP) program , which combines advanced interval
metering, and communication and control technology with a TOU rate that includes
a dispatchable "critical peak price." This program, described in more detail in
section 3, has the potential to solve a number of the problems with traditional TOU
pricing.
2. Problems with traditional residential TaU pricing
Traditional TOU pricing has typically been characterized by two or three fixed price
levels (e.peak, shoulder and off-peak) for two seasons (e.summer and non-
summer). The prices are designed to represent the average cost of generating and
delivering power to a class of customers during those periods. Potential problems
associated with traditional TOU pricing include the following:
inaccuracy of TOU prices;
revenue attrition due to overall reductions in consumption;
revenue attrition due to customer self-selection in voluntary rates; and
inadequate benefits relative to costs.
Inaccuracy of TaU prices
Utility planning and operations staff have always recognized the variability of
electricity costs. However, prior to the deregulation of wholesale power markets
these costs were largely internal to individual utilities , and not visible in public
markets. As wholesale power markets have opened up, time-varying power
generation costs have become reflected in wholesale energy prices. The
increasing opportunities for trading power in wholesale markets make these prices
the opportunity cost of power for most utilities, regardless of their mix of generation
resources.
In spite of the variability of wholesale power costs , traditional utility rate design has
focused largely on recovery of allowed costs through fixed retail prices, using
methods designed to allocate those costs fairly across various customer types.
Figure 1 illustrates the resulting disconnection that can exist between varying
wholesale energy costs and fixed retail prices. The curved line in the figure shows
hourly wholesale prices in the PJM East region for the summer of 2000, arrayed
from high to low. The flat line shows the load-weighted average of these prices,
which turns out to be approximately $50/MWh (or $.05/kWh). This value represents
a typical flat seasonal energy price that might be offered to customers in this region.
If charged in all hours, it would recover the same amount of revenue as if the actual
variable costs were charged in each hour. Note , however, that in more than 70
percent of the hours of the summer, wholesale electricity costs were less than the
average price (sometimes much less), while in more than 5 percent of the hours
electricity costs were more than twice as high as the average.
Figure 1. Disconnect Between Wholesale Energy Costs and Retail Prices
(PJM East Summer 2000)
$300
$250
$200
$150iii
$100
$50
10%20%30%40%50%60%70%80%90%100D
Cumulative Percentage of Hours
-Wholesale Price Load-weighted average
Competitive markets for other commodities tend to produce prices that reflect
production costs. The frequent wide differences between wholesale electricity
costs and retail prices suggest extensive foregone opportunities for economic gain.
That is , in an important but relatively small number of hours , the cost of producing
electricity far exceeds customers' value of consuming it, as reflected in the price
they willingly pay. Reductions in usage during these hours would save costs far in
excess of customers' forgone value of power. However , it is also important to
recognize that typical retail tariffs give customers no access to the relatively low-
cost power that is available in the vast majority of hours. Increased usage during
these periods would produce value to consumers that exceeds the cost of
generating that power.
The figure above shows costs in all hours compared to a single fixed average price.
Similar figures could be constructed to illustrate the distribution of costs in peak and
off-peak periods. While the results would undoubtedly be less extreme, the wide
distribution shown suggests that a fixed peak-period price would exceed costs in
many hours, but lie below wholesale costs during the few , but important hours of
highest costs. If customers reduce load in all peak periods, then during low-cost
hours, utilities lose more revenue than they save in avoided costs; and during high-
cost hours , utilities face costs that exceed revenues.
Section 3 describes two types of innovative TOU price structures that allow closer
matching between TOU prices and actual market costs.
Revenue attrition due to overall reductions in consumption
Under standard utility rate design methods, TOU prices are typically constructed to
be revenue neutral for customers in a particular rate class at the at the average
usage pattern for that class under standard rates. That is, the average monthly bill
under TaU prices, at the same consumption pattern used to design the flat rate,
would remain the same as under a standard flat price. Customers then have an
opportunity to lower their bill if they shift load from peak to off-peak periods under
TaU pricing. However, one typical finding from studies of customer response to
Tau prices is that in addition to shifting load from peak to off-peak periods,
customers tend to reduce overall consumption somewhat. This reduction can
cause utilities to recover less revenue than planned.
This revenue attrition is largely the result of bundled tariffs that are designed to
recover transmission and distribution costs, as well as energy costs , through a
volumetric (per kWh) price. That is, overall reductions in energy consumption lead
to corresponding reductions in the cost of energy, though not in T & 0 costs , which
are largely fixed. One potential solution to this revenue attrition problem is to
redesign TOU tariffs to recover a larger portion of T & 0 costs through monthly
customer charges, where the size ofthe charge may vary by customer size.
Revenue attrition due to customer self selection under voluntary rates
Calculating appropriate TaU prices is a reasonably straightfOlward exercise if the
rate is mandatory for a particular customer class , or group of customers (e.all
residential customers with both electric space heating and water heating). In that
case , the expected loads, and thus the expected load-weighted energy costs, can
be calculated based on existing load research data and information on expected
power costs.
However, the situation is more complicated in the case of an optional TOU rate.
The problem is caused by two factors - the diversity of customers' usage patterns
and a lack of hourly or TaU metered data for all customers. Regulated electricity
prices for residential customers are typically fixed across a broad range of
customers. The prices are set to recover the costs to serve the customers in the
class, based on metered usage data for a load research sample of customers.
However, the actual cost to serve different types of customers in the class can vary
widely, depending on the percentage of their usage that occurs in the relatively
high-cost peak period. The average cost to serve some customers may be
substantially lower than the tariff price , while the cost to serve others may be much
higher. However, without metered data , the energy supplier cannot easily
distinguish between the costs to serve individual customers.
Two possible approaches for setting the regulated prices of an optional TOU rate
illustrate the potential problems involved with traditional designs. In the first
approach , TOU prices are set to be revenue neutral to the standard tariff for the
average customer in the class (i.the TaU prices are set to recover the same
revenue as under the standard tariff, at the class-average level of usage). In the
second approach , the TOU prices are designed to be revenue neutral for those
customers that the utility expects are most likely to select the TaU rate (i. , the
TaU prices are set to recover the same revenue as under the standard tariff, after
accounting for the lower-cost usage patterns of the customers most likely to accept
the TOU rate).
In the first case, the customers most likely to choose the TOU rate are "instant
winners" who would see lower bills than under the standard tariff, even without
changing their usage pattern , since their peak-period usage is less than average.
This outcome, however, would leave the utility with less revenue than before, and is
thus not revenue neutral across both the standard and TaU tariffs.
In the second case, the customers most likely to choose the TOU rate are those
with peak-period usage that is lower even than the average of those customers
targeted" for the rate. As a result, relatively few customers are likely to choose the
TaU rate, and those that do are still likely to see lower bills (and hence lower
revenue to the utility) than if they had remained on the standard tariff, even before
any load shifting.
Possible solutions to self-selection problems
One solution to the revenue attrition dilemma posed by these two approaches is to
treat both the TaU rate and the standard tariff as optional once TOU is offered.
Each rate is then priced to reflect the expected cost to serve the customers likely to
select it. That is, the TaU prices are set to recover the 'lower expected cost of
serving the customers most likely to accept the TOU rate, and the standard tariff
prices are set to reflect the higher expected cost to serve the remaining customers.
With such designs , the utility is more likely to recover its allowed revenue, while
achieving greater participation in the TOU rate.2 This is also the natural approach
and outcome that will be followed by competitive energy suppliers offering
alternative pricing options to customers in a broad market.
2 This design is arguably more fair in that it produces less intra-class cross subsidy than a single flat rate.
Another approach to addressing the revenue erosion problem is to attempt to limit
the applicability of the TaU rate to particular customer types whose readily
identifiable characteristics are likely to imply costs to serve that are lower or higher
than average (e.customers with electric space heat and water heating). Yet
another approach is to use a two-part pricing mechanism, with a customer-specific
baseline level of usage, similar to the method used in two-part real-time pricing
programs. This approach maintains revenue by billing each customer s baseline
usage level at their standard rate, and applying TOU prices to differences between
their actual and baseline usage. It gives each customer an incentive to respond to
the TaU prices , but provides bill stability if they maintain their usage at baseline
levels. Two potential weaknesses of this approach for residential customers are a
lack of information on individual customers' baseline usage patterns , and a
perception of greater complexity compared to a standard TOU rate.
A final solution is to install advanced interval meters for all customers, and charge
prices , either flat or TaU , that reflect each customer s actual costs.
3. Innovative new types of residential TOU pricing
As noted in Section 2 , a fundamental problem with traditional TOU pricing is the
inaccuracy of TOU prices in reflecting wholesale power costs. Two new types of
TOU pricing designs show substantial promise for addressing this problem. Both
designs involve some form of variable , dispatchable pricing, in which one or more of
the TaU prices may be modified on a day-ahead , or shorter notice basis to reflect
expected wholesale market prices. One version , sometimes called "critical-peak"
pricing, involves a feature in which the peak-period price can be increased to a
higher than normal "critical" level in response to high-cost conditions in the
wholesale market. The other, exemplified by Electricity de France s (EdF) Tempo
tariff, consists of multiple sets of TOU prices that apply to different day types, which
are designated and announced a day in advance.
Recent examples of the critical price TOU approach have combined variable pricing
with communication and control technologies. The communication device allows
the utility to signal a different price depending on wholesale price conditions. Rate
structures of this type have typically taken the form of a standard three-tier TaU
rate (e.peak, off-peak and shoulder periods), with the addition of a critical price
that applies only occasionally when wholesale prices or reliability conditions reach
certain critical levels (critical price levels appear to have ranged from approximately
25 to $.50/kWh, and many programs limited the number of critical price hours to no
more than 2% of all hours). Under this approach , the standard peak period price
may be set at a level substantially below typical TOU peak-price levels, because it
does not have to cover the relatively few, but high-cost hours in which the critical
price applies.3 The lower peak.price and occasional critical price allow a better
match between TOU prices and wholesale costs. This feature may be particularly
valuable to utilities in the Pacific Northwest, where extensive hydroelectric
3 For example, Gulf Power Company s standard peak period price is $.O87/kWh, which contrasts with values
of$.l5 to .20/kWh for traditional TaU programs at other utilities.
resources keep costs low much of the time, but where infrequent tight reserve
conditions can drive wholesale market prices much higher than normal.
In addition to the communication feature of the technology, a control device gives
customers the ability to pre-set their response to both the standard and critical
prices. This feature, similar to a programmable thermostat, has been shown to
amplify the degree of customer price responsiveness, which adds to the potential
benefits of this type of TaU rate structure. Gulf Power Company in Florida has
tested a pilot critical price TaU tariff (Residential Service Variable Price, or RSVP),
and has received approval to expand the program to a target of 50 000 customers.
EdF's Tempo tariff consists of three sets of peak and off-peak TaU prices for three
day-types (e., low, moderate , and high-cost), in each of two seasons. Customers
are notified of the next day s day-type by eight p.m. (through the meter). The utility
allocates a limited number of high (22) and moderate (43) days throughout the year.
Like the critical price approach , this type of rate design allows lower peak period
prices on the low and moderate-cost day-types than under typical TaU rates , and
provides strong incentives for customers to reduce load during the relatively few
high-cost peak periods (see Section 4 for empirical evidence).
4. Evidence of TOU price responsiveness
Traditional TOU
Numerous studies have investigated how residential customers respond to TaU
prices. Many of the studies were conducted in the late 1970s and early 1980s as part
of a series of TaU experiments at a number of U.S. utilities under sponsorship of the
predecessor of the U.S. Department of Energy. Faruqui and Maiko (1983) reviewed
the findings from a variety of studies arising from these experiments. A useful
synthesis of the findings on customer response to TaU pricing can be found in Caves
et al (1984), which reports on an EPRI study of the consistency of price response
across experiments.
Caves et al found a striking consistency across the TaU experiments in the estimated
value of one typical parameter used to measure price responsiveness - the elasticity
of substitution with average values centering on approximately 0.14.4 The estimated
values also varied in sensible ways with certain household characteristics. For
example, price responsiveness was smaller (0.07) for customers with no major
appliances, and larger (0.21) for customers that had all major appliances, and thus a
greater incentive and ability to respond. In a related study, Caves and Christensen
(1980) showed that an elasticity of substitution of 0.17 was consistent with partial and
total peak-period own-price elasticities of approximately -5 and -0.3 respectively.
Analysts at the Salt River Project in Arizona estimated a peak-period own-price
elasticity of approximately -30 for a Tau experiment in the late 1980s (see Kirkeide
(1989)). This estimate focused on the response of relatively high usage residential
4 See the appendix for a definition of various price elasticity concepts.
custemers during the few heurs ceincident with system peak demands during the
summer menths.
Vo.luntary TOU
Two more recent studies reperted findings of custemer responsiveness to voluntary
TaU rates. First, Caves et al (1989) feund a relatively large substitution elasticity of
37 ameng custemers who velunteered for a TaU rate at Pacific Gas and Electric
Company. In contrast, Baladi et al (1998)feund that the velunteers fer an
experimental TaU rate at Midwest Power respended quite similarly (0.17) to.
,customers in the original nen-veluntary TaU experiments.
Variable-price TOU
A few studies have reperted price res pense findings fer TaU programs in which the
utility may dispatch different TaU prices depending on market cenditions. American
Electric Pewer (1992) reperted significant load shifting from the "high" and "critical"
price tiers to. the "Iew" and "medium" tiers , but did net estimate fermal price elasticities.
They also. reperted peak demand reductions ranging from 2 to. 3 kW per customer at
high" prices, and 3.5 to. 6.6 kW at "critical" prices. The latter values represented as
much as 60% ef custemers' peak lead during a winter period. AEP also. reperted
everwhelming custemer satisfactien with the program.
Braithwait (2000) analyzed a similar pilet program at GPU Energy. Analysis of
participant and centrol greup load data indicated that custemers modified their
usage patterns substantially in respense to the TaU prices reducing censumptien
during peak perieds and some shoulder periods , and increasing consumption
during certain eff-peak and sheulder periods. Summer peak-period load reductions
averaged about .5 kW, er 25% ef control group leads, while response during critical
price perieds ranged frem .6 to. 1.24 kW. Estimated elasticities of substitution
exceeded these in mest previeus studies ef traditienal TaU programs, indicating
streng custemer price responsiveness. Specifically, the study estimated an elasticity
ef substitutien ef 0.31 fer a censtant elasticity ef substitutien (CES) demand medel
while substitutien elasticities between peak and eff-peak perieds ef as large as 0.40
were feund using a mere flexible Generalized Leentief model.
These results illustrate the impertance of two. key factors that influence the degree of
customer respense to time-varying prices. First, relatively high peak period and
critical prices ($0.25 and $0.50/kWh , respectively) previded streng incentives
respend. Second , the interactive cemmunicatiens equipment provided the ability
respond easily, witheut customers having to remember to make manual adjustments.
Finally, Aubin , et al (1995) reperted finding strong price responsiveness and
substantial net ecenomic benefits in the experimental phase of the EdF Tempo
tariff, which they referred to. as residential real-time pricing.
The overwhelming evidence from the literature is that residential custemers de
respend to TaU prices, in a significant, and reasonably consistent and predictable
manner. The primary question is whether the net benefits to customers and utilities
from this load response are sufficient to outweigh the additional metering costs.
References
American Electric Power
, "
Report on the Variable Energy Pricing and TranstexT Advanced
Energy Management Pilot," 1992.
C. Aubin, D. Fougere, E. Husson , and M Ivaldi
, "
Real-Time Pricing of Electricity for
Residential Customers: Econometric Analysis of an Experiment,Journal of Applied
Econometrics Vol. 10, S171-S191 , 1995.
M. Baladi , J.A. Herriges and T.J. Sweeney, "Residential Response to Voluntary Time-
of-Use Electricity Rates Resource and Energy Economics 20:225-244 1998.
S. Braithwait
, "
Residential TaU Price Response in the Presence of Interactive
Communications Equipment," in Pricing in Competitive Electricity Markets, edited by A.
Faruqui and K. Eakin , Kluwer Academic Publishers, 2000.
W. Caves and loR. Christensen
, "
Econometric Analysis of Residential Time-of-Use
Electricity Pricing Experiments Joumal of Econometrics 1980.
W. Caves, L.R Christensen, W.E. Hendricks and P.E. Schoech
, "
Cost-Benefit Analysis
of Residential Time of Use Rates: A Case Study for Four Illinois Utilities,Electric
Ratemaking, Vol. 1 , No., 1982.
W. Caves , loR Christensen and J.A. Herriges
, "
Consistency of Residential Customer
Response in Time-of-Use Electricity Pricing Experiments Journal of Econometrics 1984.
W. Caves, J.A. Herriges and K. Kuester
, "
Load Shifting Under Voluntary Residential Time-
of-Use Rates The Energy Journal 10(4), 1989.
A. Faruqui and J.R Maiko
, "
The Residential Demand for Electricity by Time of Use: A
Survey of Twelve Experiments with Peak Load Pricing,Energy, Vol. 8 , No. 10, 1983.
RR Johnson
, "
Residential Meters: Adoption At Last?", Fortnightly s Energy Customer
Management Fall 2001.
lo Kirkeide
, "
Reducing Power Capacity Requirements Using Two-Period Time-of-Use
Rates with Ten-Hour Peak Periods " Masters Thesis, Arizona State University, 1989.
Levy, "Advanced Metering Scoping Study," California Energy Commission, August 2001.
Christensen Associates Analysis
Assessing the Potential Benefits of Residential Time-of-Use
Pricing at Idaho Power Company
Steve Braithwait
Christensen Associates
September 11 , 2002
The Idaho Public Utility Commission has asked Idaho Power Company (I PC) to
investigate the viability of time-of-use (TaU) pricing for its residential customers.
a July 15, 2002 memorandum , Christensen Associates provided an overview of
residential TaU pricing, including the following topics:
an historical perspective on TaU pricing,
a discussion of potential problems that can limit the benefits of residential
TaU to utilities and their customers
a description of new types of Tau pricing that show promise in addressing
some of those problems, and
a summary of evidence on customer price responsiveness.
. This report describes the results of a quantitative analysis designed to estimate the
potential benefits to Idaho Power and its customers of offering alternative types of
residential TaU pricing.
Summary
The fundamental principle of time-of-use (TaU) pricing is to charge retail prices that
vary by time period (e.summer peak and off-peak) to reflect differences in the
average cost of generating and delivering power during those periods. Billing
customers for their consumption under TaU pricing requires the installation of
meters that record energy usage during specific blocks of time. As metering
technology has advanced and become less expensive , a number of utilities are
considering the installation of advanced interval meters that record hourly usage
and thus allow more refined pricing strategies that send high prices only during
infrequent periods of high power costs (e.extremely hot summer afternoons on
which transmission constraints limit Idaho Power s access to wholesale power from
outside of its service area). This study assessed the potential benefits to Idaho
Power and its customers of both conventional TaU pricing and a form of "critical
peak" TaU pricing that would involve interval metering, and communication and
control technologies that would allow Idaho Power to send occasional critical prices
to residential customers.
This assessment involved the use of data on Idaho Power s residential customer
energy use and its hourly costs of supplying power. The analysis was conducted
using customer demand model software that simulates customers' load response to
TaU pricing, and calculates changes in consumer and utility benefits. Our primary
conclusions may be summarized as follows:
Conventional TOU pricing offers relatively small potential benefits. The primary
reason for this result is that Idaho Power s supply costs are generally low on most
days , but they rise steeply during a few hours on a limited number of days in the
summer. TOU prices that remain fixed on all days send price signals to customers
that are too high on most days , but too low on the critical few high-cost days.
Critical peak TOU pricing has the potential to produce substantial benefits.
implemented on a mandatory basis, such a pricing strategy could produce peak
load reductions on high-cost days of nearly 200 MW. Estimated benefits to
customers would exceed $1 million annually. Estimated benefits to Idaho Power
depend critically on assumptions about the costs that it avoids when customers
reduce load during critical price periods. If avoided capital costs of new peaking
capacity are considered , then the cost reductions associated with the 200 MW load
reductions under mandatory CP TOU pricing could reach $12 million per year.
Under mandatory TOU pricing, the wide range of usage patterns across all
residential customers implies that, before accounting for load response , some
customers could face bill increases of up to $20 per year, while others could face
bill reductions of similar amounts.
Implementing critical peak TaU pricing would require substantial investment in new
metering and communication equipment, and changes to Idaho Power s billing
systems. The cost of those investments has not been investigated in this study.
If Tau pricing were offered on a voluntary basis , the customers most likely to
switch to TOU would be those that would experience an immediate bill reduction
even before changing usage patterns. This would produce a revenue shortfall to
Idaho Power without rate design changes to address this "self-selection" problem.
1. Introduction
The principal argument in favor ofTOU pricing has always been economic
efficiency i. e.TOU prices reflect differences in the average cost of generating
and delivering power during particular time periods , thus providing more appropriate
price signals to customers than do flat rates. Customers can achieve benefits
under TOU pricing if they can shift sufficient consumption from peak-period hours
in which the price exceeds the standard flat price, to lower-price off-peak hours.
Utilities can realize net gains from those same load shifts by avoiding some peak
period sales whose cost exceeds the revenue generated, and selling more during
low-cost off-peak periods. However, these TaU benefits must be traded off against
higher metering and administrative costs.
Estimates of that benefit-cost tradeoff have generally not been favorable. Two main
factors have weighed against the benefits of TOU pricing for residential customers.
First, TaU prices do not reflect the variability of wholesale power costs with
sufficient accuracy. For example, peak period prices (e.10/kWh) are generally
designed to represent an average across expected wholesale costs during peak-
period hours in a given season (e.summer).1 However, wholesale power costs
can range widely from moderate to very-high levels, depending on actual load
levels and supply conditions. In many hours, TOU peak period prices substantially
exceed the actual cost of power (e.a TOU price of $.10/kWh versus a wholesale
cost of $.03 to $.05/kWh). However, in the very hours in which costs reach their
highest levels , the peak period price is likely to fall far short of that level (e.
10/kWh versus costs of $.50 to $1.00/kWh or more). Thus , while TOU prices do a
better job than does a flat price of reflecting cost differences on average, the price
signal is still not very accurate. When TOU customers reduce load during the many
peak hours in which costs are actually relatively low , utilities' revenue can be
reduced by more than their costs.
Second , the relatively low usage level of residential customers, combined with the
first factor of inaccurate prices , limits the overall magnitude of potential benefits
from customers' responses to TOU prices. These benefits must be traded off
against the additional cost of metering and billing.
TOU rates have generally not been mandated , or established as the default tariff for
residential customers. Most TOU programs have been offered as voluntary
programs, typically targeted at customers with high usage levels, or ownership of
major appliances such as central air conditioning or pool pumps. As a result, most
residential TOU tariffs have relatively few customers.
Two recent programs promoted by Puget Sound Energy (PSE) in Washington
State, and Gulf Power Company in Florida , provide indications of potential renewed
interest in residential TOU. PSE has undertaken an ambitious program to install
advanced interval meters for all of its residential customers, along with software and
communication devices that give customers the ability to monitor their energy
usage and PSE's wholesale power costs online. PSE has assigned all customers
with the new meters to a TOU rate , although customers have the right to opt out
and return to a flat rate. PSE claims that a large share of the cost of the metering
and communications system may be covered by improved meter reading and billing
efficiency, even before accounting for the benefits associated with customer load
response to TOU prices. PSE has also discussed a range of potential advanced
pricing approaches that they may consider offering to take advantage of the
metering and communications capabilities.
Gulf Power has recently announced a planned expansion of their pilot Residential
Service Variable Price (RSVP) program, which combines advanced interval
1 To cover expected costs, TaU prices actually need to reflect a load-weighted average of hourly wholesale
costs, where the weights represent the load pattern of the customers expected to take service under the rate.
metering, and communication and control technology with a TOU rate that includes
a dispatchable "critical peak" price. This program , a version of which is assessed in
this report, has the potential to solve a number of the problems with traditional TOU
pricing.
Our understanding is that Idaho Power Company currently faces a situation of
increasing demand and transmission constraints that limit access to generation
resources to the west. As a result, the company is considering plans to build
additional peaking capacity. Thus, a dynamic pricing program that provided load
reductions during key peak demand periods could provide valuable cost savings.
2. Overview of Quantitative Assessment
This report describes the analyses that we have conducted to assess the viability of
. residential TOU pricing at Idaho Power. We have analyzed variations on two
general types of TOU pricing strategies - a conventional TOU tariff and a "critical
peak" (CP) TaU tariff which consists of a standard TOU rate plus the ability of the
utility to send a "critical" price on a limited number of days during the peak period
with day-ahead notice. We considered mandatory and voluntary versions of these
two general TaU pricing strategies.
Analytical Tools and Data
Calculating the benefits of TaU pricing requires certain types of analytical tools and
data. The principle benefits from TOU pricing result from customers' demand
response to the TaU prices relative to their former flat price. Thus, developing
estimates of TOU benefits requires an analytical model of customer demand for
electricity by time period. In this study, we have calculated the benefits to
customers and the utility using customer demand model software (implemented in
Excel spreadsheets) that characterizes customers' hourly demands for electricity
(relative to a reference load) as a function of Tau prices relative to prices from a
reference period? The model first calculates hourly changes in loads in response
to changes in TaU prices , then calculates the changes in customer benefits
(technically, consumer surplus) and utility net benefits (changes in revenue less
changes in cost) associated with those load changes , and finally adds up the
changes over all hours in the period of analysis.3 In cases where TOU pricing is.
voluntary, customers may choose the TOU tariff if they believe that they would be
better off facing TOU prices. To simulate this choice , the demand model contains a
simple choice model, in which customers' probability of selecting the TOU rate
depends on their estimated benefits from TOU pricing, scaled as the percentage
change relative to their base bill under the flat rate.
The demand model requires several types of input data and behavioral parameter
assumptions. The data include historical hourly customer loads and wholesale
2 A technical description of the customer demand model is provided in an appendix.
1n the case of regulated utilities such as Idaho Power, the benefits to the utility may largely be thought ofas
benefits to all of the utility's customers. For example, load reductions that produce avoided costs that exceed
foregone revenue imply that retail rates in the future will be less than would otherwise be the case.
costs , and forecasts of wholesale costs for the period of analysis. The parameters
include price elasticities that characterize the extent to which different types of
customers respond to time-varying and overall electricity prices , and parameters
that represent customers' likelihood of accepting TOU pricing ifoffered on a
voluntary basis. Christensen Associates has extensive experience in both
estimating price response parameters for customers facing TaU pricing, and
compiling literature reviews of parameter values estimated in other studies.
Historical load and wholesale cost data
For purposes of this analysis , we used historical data from 1999 on customer loads
and wholesale costs. This was the most recent year that was not "contaminated"
by the extreme conditions that held in the West due to the California crisis of 2000-
2001. Idaho Power provided hourly load research sample data for 1999. After
exclusions for missing data , we were left with high quality data on hourly loads for a
random sample of 94 customers that represented the wide range of usage patterns
of Idaho Power s residential customers.
Constructing historical wholesale cost data required several steps. In principle, we
wished to represent Idaho Power s hourly opportunity cost of generating,
purchasing or selling power. IPC staff suggested using Mid-Columbia wholesale
prices to represent those values. However, IPC only maintained historical records
of the daily average peak and off-peak prices for 1999. To allocate those prices to
hours of the day, we applied hourly patterns of the California day-ahead PX prices
for each day in 1999. Finally, we decided that it was appropriate to smooth out
certain uncharacteristic seasonal price patterns in the historical data by using
expected seasonal patterns from wholesale price. forecasts provided by IP.
Figure 1 illustrates the variability of IP's power costs. The curve shows the
distribution of daily (weekday) five-hour peak average wholesale costs during June
through September 1999 (e.the average cost for hours 14 through 18). The
solid flat line shows the overall average summer peak-period cost, which would
normally serve as the basis for a peak period TaU price. The classic asymmetric
shape of the price distribution illustrates one of the typical problems of TaU pricing
- a TaU peak price based on the average cost across all days exceeds the actual
cost of power on more than two-thirds of the summer days, while on the dozen days
of the highest costs the actual cost of power exceeds the average cost by more
than fifty percent. When customers reduce load in response to peak TOU prices on
days of relatively low costs , the utility loses more in revenue than it avoids in cost.
Only on the relatively few high cost days does the utility save more in avoided cost
than it loses in revenue from the load reductions.
4 The utility also potentially loses revenue from the non-energy portion of the rate if consumers reduce load by
more in the peak periods than they increase usage in off-peak periods. This suggests that a larger portion of
non-energy costs be recovered through customer charges rather than energy charges, particularly to the extent
that the costs are fixed and not affected by changes in energy consumption.
The potential value of the CP TaU pricing approach can be seen in the dashed flat
line, which shows average costs after excluding the twelve highest-cost days.
that case, the peak price provides a better approximation of normal peak-period
costs , and the higher critical peak price on the highest-cost days encourages
greater load response on those days.
Wholesale cost scenarios
We produced results for two alternative wholesale cost scenarios. One used the
actual costs that occurred in 1999. The other was designed to represent a high-
cost scenario, in which the costs for the 100 highest-cost hours were increased by
gradually greater amounts such that the highest price equaled $500/MWh , rather
than the actual historical maximum of approximately $200/MWh.
Customer price responsiveness
The customer demand model represents customers' price responsiveness by two
main types of parameters - elasticites of substitution that represent customers
willingness to shift load from high-price to low-price time periods , and an overall
price elasticity that represents customers' propensity to change their overall
electricity consumption due to any change in the overall average price of electricity.
Since the focus of this study was on customer response to time-varying prices, we
set the overall price elasticity equal to zero.
We applied a range of elasticity of substitution values across the customers in the
load research sample, where the values were based on two key factors that have
been observed in previous analyses. First, reasonably consistent values of these
elasticities have been found in a variety of conventional TaU pricing studies , with
average values ranging from approximately .05 to ., and higher values typically
estimated for customers with major electricity-consuming devices such as central
air conditioning, and electric space and water heating. Second , we have found
substantially greater price responsiveness among customers facing critical price
TaU programs, particularly for those in which the program involves communication
and control technology that allows customers to pre-specify their response to TaU
and critical prices, as in raising air conditioning thermostat settings. In one study,
we found elasticities of substitution that approximately doubled the estimates under
conventional TaU pricing.
We incorporated these findings in the following way. First, we assigned elasticities
to the sample customers in a random fashion , after adjusting each customer
probability of receiving a given value such that customers with greater (less) than
average annual usage had a greater (less) chance of receiving a larger elasticity
parameter. Second , the parameters assigned for the CP TaU case were
approximately double those of the Base TaU case. For the latter case, the
assigned values ranged from .05 to ., while for the CP case, they ranged from .
to .30.
TOU Pricing Strategies
The TOU prices were calculated according to two principles. First, the ratio of peak
to off-peak energy prices was set to reflect the ratio of the load-weighted average
wholesale power cost in those time periods. Second , the actual price levels were
calculated so as to generate the same revenue as under the standard flat tariff
price , at the customers' baseline level of consumption. Only the energy portion of
the standard tariff price (i.the unbundled power supply and PCA rate component)
was adjusted to reflect time-varying costs; the remaining portion of the tariff price,
which represented about half of the total price, remained constant across time
periods.
For the CP TOU strategy, we assumed a CP energy price of $.20/kWh , and
assumed that it would be implemented on average during 60 hours of the year.5 To
calculate the TOU prices that apply during the remaining hours of the year, we first
subtracted the revenue generated in the assumed 60 critical hours , then calculated
the price ratios and revenue-neutral prices for the remainder of the revenue
requirement.
For purposes of this relatively high-level analysis, we felt that it was appropriate to
focus only on peak and off-peak pricing periods. A more comprehensive analysis
could examine a third set of "shoulder" period prices as well. Analysis of the
wholesale power costs across hours suggested that the optimal peak period for the
June through September summer period was the five hours of 1 p.m. to 6 p.m. (i.
hours ending 14 through 18), while for the remaining months it was 14 hours from 7
m. to 9 p.6 Table 1 summarizes the relevant prices.
Table 1: TOU Prices
Winter Prices
Summer Prices (cents/kWh)(cents/kWh)
Peak Off-peak Critical Peak Off-Deak
Flat
Base TOU
Critical Price TOU 22.45
5 For reference, GPU Energy used a critical price of$.50/kWh in a pilot CP TaU program in 1997, and Gulf
Power has set its critical price at $.29/kWh. We used a somewhat lower price in view ofIPC's generally lower
costs.6 The optimal peak periods minimize the variability of prices within the period, while maximizing the
difference between the average variability between the two periods.
3. Effects of TOU Pricing
Analysis of Changes in Energy Consumption and Benefits
As described above, the customer demand model first calculates changes in
customer usage patterns under TaU pricing. These load changes are then used to
calculate changes in consumer benefits , and changes in utility net revenues. In the
case of voluntary TaU , the changes in consumer and utility benefits are calculated
only for that percentage of customers that are estimated likely to adopt TOU pricing.
Before turning to the quantitative results, we first summarize the source of and
method for calculating consumer benefits from TaU pricing. It is instructive to
illustrate changes in consumer benefits in two stages. First, consider the bill
changes induced by the revenue neutral (at average baseline usage) TaU design
as shown in Figure 2. The higher prices during the peak periods, and the lower
prices during off-peak periods , relative to the flat price , imply peak-period bill
increases and off-peak bill reductions. For the average pattern of baseline usage
these bill changes offset each other completely, leaving no net annual bill change
(i.revenue neutrality) before accounting for any load response. However, the
wide range of usage patterns in the residential class implies that some customers
(e.those with a greater than average share of peak period usage) will experience
overall bill increases, while others (e.those with a less than average share of
peak period usage) will see bill reductions even before undertaking any load
response.
To illustrate , Figure 3 shows the distribution across customers of annual bill
changes before load response for the Base TaU pricing case. The distribution is
reasonably symmetric, with relatively small bill changes ranging from approximately
$20 bill reductions , to $20 bill increases per year. (Note that under the current flat
price those customers with relatively less usage during the higher-cost summer
peak periods cost less to serve than the average customer, and are thus effectively
subsidizing customers with relatively high usage during those periods).
Figure 4 illustrates how customers can benefit from load changes in both peak and
off-peak periods. Economists traditionally measure changes in consumer benefits
due to price changes as changes in consumer surplus which can be thought of as
the difference between what consumers are willing to pay for a certain amount of a
product (as reflected in their demand curve) and the market price that they actually
have to pay. A conventional downward sloping demand curve reflects the value
that consumers attach to a product or service; it implies that consumers are willing
to purchase more of a product as its price falls, or less of it as its price rises. The
right panel of Figure 4 shows that the average consumer who purchased Qoop in
the off-peak period at the flat price , PF, increased consumption to QTOUOp at the
lower off-peak price, and experienced an increase in benefits equal to the triangular
area under the demand curve and above the off-peak price, PoP.
The left panel shows that during the peak period the average consumer who
purchased Qop in the peak period at the flat price, reduced consumption to Q TOUp at
the now higher peak price, Pp. By reducing consumption , he reduced his bill by the
rectangular area bounded by the two price lines and the amount of the load
reduction. However, he also lost some value from the foregone consumption (e.
experienced some discomfort after raising the air conditioner thermostat setting on
a hot day), as indicated by the triangular area under the demand curve. The net
result is a gain in value equal to the bill reduction less the foregone value?
Estimates of TOU Pricing Impacts
Table 2 summarizes the estimated changes in various key electricity consumption
financial, and customer benefit variables for each of the pricing strategies examined
in this analysis. The following are comments on specific results, starting from the
left-most columns.
1. Load changes. The first set of columns shows changes in demand (in MW).
Two values are shown. The first is the change during the hour of maximum
demand (regardless of wholesale cost) for the entire class. The second
shows the change in the hour of highest wholesale cost. The Base TOU
case produces the greatest impact in the coincident peak hour, while the
load response for the CP TOU cases is much larger during the important
high-cost hour. The mandatory version of CP TaU suggests a maximum
potential of nearly 200 MW of load reductions at times that critical prices
apply.
2. Utility impacts. The second set of columns shows effects on Idaho Power
revenues, costs, and net revenues of the load shifting induced by the TOU
pricing, under both the base and high-cost scenarios. For the two mandatory
cases, the reductions in revenue occur as a result of customer load changes.
Under the voluntary cases, the revenue reductions occur as a result of both
instant" bill reductions for participating customers as well as their load
reductions.
The reductions in cost result from the energy costs avoided by customers
shifting load on net from high-cost to low-cost hours. Under the base
assumption of the costs that occurred in 1999, the cost reductions in most
cases are less than the revenue reductions. Under the high-cost scenario,
cost reductions in the two mandatory TOU cases exceed revenue losses
showing the potential net benefits to the utility and its customers. In the two
voluntary cases , the revenue losses from voluntary self selection exceed the
7 The actual amounts of both bill reduction and foregone value from the load reduction include the unshaded
rectangle below PF and between the two quantity levels. However, these changes cancel, leading to the focus
on the shaded areas.8 The load changes and resulting impacts on utility costs were inflated by an estimate of transmission and
distribution line losses. We assumed an average value of seven percent. Thus, a 1 MW load reduction
measured by meters at the customer level translates into a 1.07 MW reduction in Idaho Power generation
requirements.
cost reductions. However, it should be pointed out that alternative TOU rate
designs can be used to address the revenue attrition problem caused by
customer self selection.
Finally, Idaho Power may be able to count an additional benefit of the TOU
load reductions to the extent that they allow the utility to avoid or postpone
the need for additional peaking capacity. For example , under an assumption
of a capital cost for peaking capacity of $500/kW for a unit that, is expected to
run for approximately 50 hours per year , and an annual capital charge rate of
12%, then a 100 MW load reduction during the same number of hours could
be considered to avoid the cost of $60/kW * 100 MW * 1000 kW/MW = $6
million per year. Thus , the 200 MW load reduction of the mandatory CP
TOU would produce $12 million in capital cost savings.
3. Customer benefits. The third set of columns shows changes in consumer
net benefits , in both a dollar amount and as a percentage of the total base
bill before load shifting. The total change in net benefits is comprised of two
components. One is the "instant" bill changes that consumers see from the
change to TOU prices (e., customers with greater than average energy
consumption in the non-summer and off-peak periods receive an immediate
bill reduction from the TOU prices). In the mandatory cases , these instant
bill changes net out to effectively zero , reflecting the revenue neutrality
assumption. The second component represents "load response" gains due
to consumers shifting load from peak to off-peak periods. The percent of
base bill value provides a useful relative measure of the magnitude of
benefits. In previous analyses, we have seen gains in net benefits as a
percent of base bill range from less than 1 % to approximately 2 - 3%. The
magnitude of net benefits depends on two key factors - the degree of price
variability (e., the difference between peak, off-peak and critical prices) and
customers' flexibility to change usage patterns.
Total annual net benefits for each TOU option under each cost scenario may
be obtained by adding the total customer net benefits to the utility s net
revenue change in the relevant cost scenario. These results provide one key
input to the assessment of the viability of TOU pricing at Idaho Power.
arrive at a complete assessment of the benefits and costs of the TOU pricing
strategies, one would need to compare the costs of the required metering
equipment to a discounted stream of annual net benefits ,such as those in the
table, over a reasonable time period.
4. Participation. The next set of columns shows participation rates in the two
voluntary options as a percentage of load and. of the number of customers.
9 For example, once the TaU rate is offered as a voluntary rate, the standard flat rate also becomes voluntary.
Thus, each should be priced to reflect the costs ofthe customers most likely to select each rate. This would
suggest higher flat prices to reflect the relatively higher cost to serve customers that do not immediately benefit
from the TaU prices.
An assumption underlying the relatively small TOU participation rates is that
customers have some inertia that tends to make them reluctant to change
pricing options, particularly for the relatively small gains reflected in these
examples , such that they do not automatically adopt a TOU option even if it
appears to deliver positive net benefits. The number of customers
participating in the voluntary cases may be calculated by recognizing that
Idaho Power had approximately 300 000 residential customers in 1999.
5. The last column shows the percentage of customers that would experience
negative net benefits under each case. Under the mandatory cases
approximately half of the customers would gain at the expense of the other
half, as seen in Figure 3 above. In the voluntary cases, even some
customers that experience bill increases have some probability of
volunteering for the TOU price.
4. Conclusions
Conventional TOU pricing applied on a mandatory basis to IPC's residential
customers would produce very modest potential benefits. This result is due to the
relatively small differential between average peak and off-peak wholesale costs,
and thus the retail TOU prices; as well as the general lack of correspondence
between average peak costs and the day-to-day variations in those costs. Making
TOU pricing voluntary produces somewhat higher consumer benefits , but results in
net revenue losses to Idaho Power due to customers self selecting the TOU rate
whenever it offers immediate bill (and revenue) reductions.
Critical peak TOU pricing appears to provide the potential for beneficial load
reductions and cost savings. It would produce much larger demand reductions
during the most important high-cost hours than does conventional TOU. Customer
net benefits are also higher due to the greater opportunity for benefits from load
reductions during critical price periods. The results for the mandatory case indicate
a potential gain of more than $1 million annually. From the standpoint of Idaho
Power, however, the key factor affecting potential benefits is the nature of the costs
that would be avoided by customers' load reductions. Under the base cost
scenario , cost reductions fall short of revenue reductions, yielding a large net
revenue reduction.10 However, cost reductions under the high-cost scenario
exceed the revenue reductions , producing net gains to the utility.
In addition , if the load reductions can be credited with avoided capital costs for new
peaking capacity, then the value of the load reductions may be substantially higher
than the cost reductions shown in Table 2.
A more realistic case might be that CP TOU would be offered on a voluntary basis.
In this case , careful rate design would be required to limit the extent of revenue
losses from customer self selection. Under the assumptions in our analysis, a
10 In actual operation, the critical prices might not be dispatched for as many days under the base cost scenario
as was assumed in the analysis. This would limit the amount of net revenue losses.
market share of 25% would produce load reductions of approximately 40 MW
during critical price conditions.
Finally, any of the above cases of estimated benefits must be traded off against the
cost to Idaho Power of installing advanced interval metering equipment and
modifying its billing systems to account for TOU pricing.
-= 100
(I') 80
Figure 1: Distribution of Wholesale Power Costs
A verage Daily Peak-period Values (1 m. - 6
180
160
140
120
40
....... - - - ...... - - - --------
135 7 9111315171921232527293133353739414345474951535557596163656769717375777981838587
!-Avg -PeaIcPrice PeakPrice(CP)!
Figure 2: Revenue Neutrality of TOU Prices at Baseline Consumption
Peak
$/kWh
kWh
$/kWh
Off-Peak
POP
Q~p kWh
Figure 3: Distribution of Bill Changes Before Load Response
Mandatory Base TOU ($/year)
25.
20.
15.
10.
tit
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
(5.
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Figure 4: Customer Benefits from TOU Pricing
Peak
Cost of
responding
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$/kWh
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Off-Peak
Net benefit
(added value)
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Appendix: Demand Model Documentation
The demand response model incorporated in the spreadsheet software is based on the
nested constant elasticity of substitution (CES) demand model. The CBS functional fonD
has been widely used to characterize customer response to time-varying prices, including
both time-of-use (TaU) and hourly prices.
The nested CES (NCES) is derived from a customer cost function that allocates
electricity costs separately within and between days. That is , a customer
overall electricity costs are represented by a function of daily price indexes
which inturn are functions of the hourly (or TOU) prices on each day. Customers
choose levels of electricity demand that minimize overall costs with respect to the
time-varying prices, while maintaining the level of services implied by a historical
usage pattern at historical prices. The model allows two levels of customer
flexibility to respond to time-varying electricity prices. One level involves the
flexibility of customers to shift load between hours or time periods within a day;
the other level allows the flexibility to shift load between days in response to
changes in the average price level between different days.
The daily price index for day , Dd, is specified via the CES functional form as a
load-weighted average of elasticity-adjusted hourly prices Ph in that day:
(1-aw)Xl-aW)
hEd
where CXhd is a load shape parameter that approximates the fraction of daily load
in hour and D"w is the within-day elasticity of substitution parameter. Next, the
aggregate monthly price index Mm, also given as a CES function , is a load-
weighted average of elasticity-adjusted daily prices Dd in that month:
. =(~PdD:--~' t-."
where f3d is a second load shape parameter that approximates the fraction of
aggregate monthly load that occurs in day and D"b is the between-day elasticity
of substitution parameter.
The customer s demand for electricity may then be obtained by applying
Shepard's Lemma to the above cost functions , differentiating the cost function
with respect to the input price. It is most convenient to specify the resulting
demand equations relative to an average reference load and in logarithm form
as shown in the following:
In()=ff+(In()JM
In(
)J'
Edh represents electricity usage in hour (or time period) on day , Pdh is the
price , and the daily and monthly price indexes are as defined above. The
variables in the denominator with the super bar represent averages of the
variable for the comparable time period in the reference period (e.the average
load in hour on weekdays in a given month. The demand equations have two
types of parameters. The load shape parameters (CXhd and !3d) characterize the
inherent shape of the customer s load pattern and are used to construct the daily
and monthly price indexes. The price response parameters (O'w and O'b)
characterize how the load responds to changing hourly prices. In this study, we
assumed that the two price response parameters take on the same value, , O'w
O'b, and refer to that value as the elasticity of substitution.
Given prices and loads in a baseline period , assumptions about price response
parameters , and prices in an alternative scenario, the model calculates customer
demands in each time period.
ISSUES SPECIFIC TO IDAHO POWER
Two issues which directly affect the viability of time-of-use pricing for
Idaho Power are the current status of the Company s metering capability and the
PCA treatment of benefits associated with reductions in power supply costs
which may result from the shifting of customer loads to off-peak periods. Any
potential benefits from time-of-use pricing must be traded off against the costs of
the metering equipment and billing system modifications necessary to record and
bill interval usage. In addition , any power supply related benefits from time-of-
use pricing should flow through the PCA in a manner that is fair and equitable to
customers and the Company.
Meterinq Capability. The analysis performed by Christensen Associates
did not include any cost component for the metering equipment necessary to
record usage by time period. Idaho Power currently does not have metering
equipment in place to record usage by time period for residential customers.
There are two options which could be utilized to provide the ability to record
usage by time-of-use. First, standard time-of-use meters could be installed.
These meters have an internal clock and calendar and are programmed to record
usage during the time-of-use periods. Usage data is retrieved monthly during the
Company s standard meter reading process. If the hours included in the time-of-
use periods change, these meters must be physically reprogrammed through a
site visit. In addition , because usage information from several registers must be
retrieved when these meters are read, additional administrative costs associated
with the increased meter reading time is incurred. Second , an automated meter
reading (AMR) system could be installed. With an AMR system, meters are read
via the power line or radio frequency depending on the application. Changes to
time-of-use periods can easily be made via the remote communication capability
of an AMR system. Because an AMR system reads meters remotely, updated
usage information can be collected on an "at will" basis, allowing for more timely
information to be provided to customers. The average cost to install a standard
time-of-use meter for a residential customer would be about $145 per customer
or approximately $47 million for all residential customers system-wide. The
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.
PCA Implications . Benefits result from time-of-use pricing when
customers are able to reduce their bills and utilities are able to reduce their costs
by an amount greater than the reduction in revenue. Assuming that a time-of-
use scenario that successfully addresses the potential revenue attrition problems
identified by Christensen Associates could be constructed, a time-of-use
scenario cannot be beneficial to Idaho Power without a modification to the
...
manner in which reductions in power supply costs which result from customers
load shifting are treated in the Power Cost Adjustment (PCA) mechanism. Under
the current PCA methodology, 90% of the reductions in power supply costs that
accrue as a result of customers shifting load from the on-peak to the off-peak
period are passed through to customers as a benefit. Idaho Power is able to
retain only 10% of the benefit. However, Idaho Power absorbs 100% of the
reduction in revenue. The 90/10 sharing of the benefits associated with reduced
power supply costs would result in a negative impact to Idaho Power s earnings.
The following example, in which it is assumed that customers' load shifting
resulted in a decrease in power supply costs greater than the reduction in
revenue, illustrates the situation.
Impact for Utility Without PCA Mechanism
Reduction in revenue due to reduced customer billings
Reduction in power supply costs due to customers
shifting load to off-peak time period
Impact to Utility s earnings
$ (90 000)
$(130.000)
$ 40,000
In this example, the net impact to the utility s earnings is an increase of
$40,000.
Impact for Idaho Power With PCA Mechanism
Reduction in revenue due to reduced customer billings
Reduction in power supply costs due to customers
shifting load to off-peak time period $(130,000)
Idaho Power s 10% share of reduced costs $(130,000*10%)
Impact to Idaho Power s earnings
$ (90,000)
$(13.000)
$(77 000)
In this example, the net impact to Idaho Power s earnings is a decrease of
$77,000.
The PCA treatment of benefits associated with reductions in power supply
expenses that could accrue as a result of customers shifting load in response to
time-of-use pricing must be addressed to remove the negative impact to Idaho
Power s earnings in order for time-of-use pricing to have the opportunity to be
viable.
Energy Efficiency Advisory Group
Input from the Energy Efficiency Advisory Group (EEAG) indicates support
for implementing pricing that requires customers to pay what it costs to receive
service. The EEAG supported pricing that lets customers who use less energy
during the on-peak period pay less and requires customers who use more energy
during the on-peak period to pay more. Overall the group was more supportive
of increasing the charges for the standard tariff service and making both the
standard service and time-of-use service optional than it was of making time-of-
use mandatory. Some concern was expressed for those who may have a difficult
time paying more for energy used during the on-peak period; however
recognition was made that customers should pay for the service they receive.
The EEAG expressed the sentiment that it appeared to be more sensible
to pursue a demand response program than a time-of-use pricing program at this
time given the investment in metering equipment that would be necessary to
accommodate a wide-scale time-of-use program. A demand response program
that targeted a reduction in load during only those high cost hours in which the
economics indicated it was beneficial to do so appeared , according to the EEAG,
to be an option that might have merit.
Although time-of-use pricing could be offered using standard time-of-use
meters, the EEAG believed that it would be important to the program s success
to provide customers with the additional information that would be available
through an AMR system. In addition, the EEAG indicated customers would be
willing to pay more to have the additional information available.
The EEAG discussed the potential of installing time-of-use meters in new
subdivisions and housing developments. However, the EEAG did not support
mandatory time-of-use pricing for these customers nor did the EEAG support
cost shifting of additional meter related costs to non-participants. Consequently,
EEAG did not support the suggestion that all new developments be equipped
with time-of-use meters.
Conclusions
Some of the new types of time-of-use pricing, particularly the critical peak
TOU structure , may have potential as viable pricing options for residential
customers at some time in the future. However, any benefits that may result
from time-of-use pricing must be balanced against the costs of the equipment
necessary to accommodate the pricing. Idaho Power currently does not have a
metering system in place to accommodate a large-scale time-of-use pricing
program for residential customers. The cost of installing standard time-of-use
meters , which would not allow for the "critical peak" or "day type" designs , does
not appear to be economic given the potential benefits that might accrue from
load shifting given the relatively small loads of residential customers. Until such
time as an AMR system is available on Idaho Power s system, and a PCA
methodology is devised to remove the negative impact to Idaho Power s earnings
due to the unequal treatment of the revenues and expenses impacted by load
shifting, residential time-of-use pricing is not economically viable.