Assessing the Potential for Dispatchable Load Management Measures:
Annotated Bibliography of References, Reports, and Other Information
Sources
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Contents
1.
INTRODUCTION ................................................................................................................................ 1
2.
BACKGROUND ................................................................................................................................... 1
3.
KEY FINDINGS ................................................................................................................................... 3
4.
UTILITY DLM PROGRAM DESCRIPTIONS ................................................................................ 5
4.1.
4.2.
4.3.
4.4.
4.5.
5.
NORTHERN STATES POWER (NSP) .................................................................................................. 5
FLORIDA POWER CORPORATION (FPC) ........................................................................................... 6
CINERGY ......................................................................................................................................... 6
DUKE POWER .................................................................................................................................. 7
GREAT RIVER ENERGY .................................................................................................................... 9
EQUIPMENT & SERVICES VENDOR DESCRIPTIONS ............................................................. 9
5.1.
5.2.
5.3.
CANNON TECHNOLOGIES ................................................................................................................ 9
COMVERGE TECHNOLOGIES, INC....................................................................................................10
SILICON ENERGY ............................................................................................................................11
6.
CAPSULE DESCRIPTIONS OF EPRI LITERATURE .................................................................11
7.
OTHER GENERAL LITERATURE AND REPORTS WORTHY OF NOTE .............................14
8. LITERATURE AND INFORMATION SPECIFICALLY FOCUSED ON AGRICULTURAL
LOAD MANAGEMENT ............................................................................................................................16
8.1.
8.2.
LISTING OF PERTINENT AGRICULTURAL LOAD MANAGEMENT LITERATURE .................................16
KEY Q-AND-A REGARDING TECHNICAL FEASIBILITY OF AGRICULTURAL PUMP LOAD CONTROL .17
9. LITERATURE AND INFORMATION SPECIFICALLY FOCUSED ON COMMERCIAL AND
INDUSTRIAL NON-FIRM RATES ..........................................................................................................19
9.1. KEY RATE DESIGN VARIABLES ......................................................................................................20
9.2. DEFINING GENERIC INTERRUPTIBLE/CURTAILABLE PROGRAM CHARACTERISTICS &
PARTICIPATION RATES ...............................................................................................................................21
10.
ADDITIONAL LITERATURE ON ENVIRONMENTAL AND REGULATORY ASPECTS
OF STAND-BY AND ON-SITE GENERATION .....................................................................................26
10.1.
10.2.
ENVIRONMENTAL EMISSIONS CONSIDERATIONS ........................................................................26
PERMITTING AND LICENSING REQUIREMENTS ............................................................................27
11. ADDITIONAL NOTES ON THE LITERATURE REVIEW PROCESS .......................................28
12.
TEMPLATES FOR CANDIDATE DLM MEASURES ...............................................................29
RESIDENTIAL INTERACTIVE THERMOSTAT SET POINT CONTROL PROGRAM ..............................................31
RESIDENTIAL ELECTRIC WATER HEATER (EWH) LOAD CONTROL............................................................34
RESIDENTIAL THERMAL STORAGE (W/ CERAMIC BRICKS) ..........................................................................37
RESIDENTIAL DUAL-FUEL (W/ DIESEL OR LP) ............................................................................................37
AGRICULTURAL/IRRIGATION PUMPING LOAD CONTROL ............................................................................41
COMMERCIAL & INDUSTRIAL CURTAILABLE RATE W/ DAILY LOAD PROFILING & BUY-BACK (“DEMAND
EXCHANGE”) ..............................................................................................................................................44
STANDBY GENERATOR PROGRAM W/ SELL BACK BASED ON SPOT PRICES ..................................................48
COMMERCIAL/INDUSTRIAL REAL-TIME PRICING .......................................................................................51
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List of Tables
TABLE 1: REPORTED PEAK LOAD REDUCTIONS FOR ELECTRIC UTILITY DSM PROGRAMS, ............................ 2
TABLE 2: PEAK LOAD REDUCTION 1990-1993 BY CLASS OF OWNERSHIP ....................................................... 2
TABLE 3: EXAMPLES OF “TRADITIONAL” AND “NEXT GENERATION” DLM MEASURES ................................. 4
TABLE 4: TEN LARGEST LOAD MANAGEMENT UTILITIES ............................................................................... 5
TABLE 5: AVERAGE CUSTOMER SIZE, AVERAGE LOAD RELIEF, COMPLIANCE LEVELS FOR FIVE
INTERRUPTIBLE AND CURTAILABLE PROGRAMS (SOURCE: REFERENCE 1 ..............................................23
TABLE 6: COMMERCIAL/INDUSTRIAL MARKET PREFERENCES FOR VARIOUS .................................................24
TABLE 7: COMMERCIAL/INDUSTRIAL NON-FIRM RATES MODELING ASSUMPTIONS ......................................25
TABLE 8: CANDIDATE DLM MEASURES FOR BPA CONSIDERATION .........................................................30
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1. Introduction
This effort seeks to quantify the potential for Dispatchable Load Management (DLM)
measures that either meet Bonneville Power Adninistration’s (BPA’s) system peaking
requirements or provide BPA with some strategic or market advantage in terms of selling
energy to neighboring systems.
The assessment effort is divided into three parts:
1. Perform a literature search or all information resources pertinent to identify candidate
DLM measures;
2. Based on the information obtained in the literature search, conduct a classification
analysis to screen the identified DLM measures for applicability to the Pacific
Northwest; and
3. Develop a “BPA DLM Resource stack”, i.e., a quantification of the most-promising
measures that can be used to define the technical potential for a DSM project in the
BPA service territory.
This report is the deliverable for the first part of the assessment effort.
2. Background
Dispatchable Load Management (DLM) has historically been one of the most significant
demand-side resources at the disposal of electric utilities. DLM is distinct and easily
recognizable by its focus on load or demand reductions, usually at system peak, as
opposed to energy efficiency improvements.
DLM measures have often been grouped into two categories:
 The direct load control approach, where the appliance is controlled directly by the
utility system dispatcher; and
 The interruptible/ curtailable approach, where the dispatcher notifies the customer
of the need for demand reduction, but the customer is responsible for implementing
the load management. Recently, many new types of DLM approaches are blurring
this distinction and adding entirely new categories of DLM schemes.
The Energy Information Agency of the U.S. DOE keeps track of both energy savings and
demand reduction in their annual reports entitled “US Electric Utility Demand-Side
Management”. The aggregate results they report, reproduced in Table 1 below, show a
steady growth in both direct control-type programs and interruptible/curtailable-type
programs. At the national level, both types of DLM together grew from 7,900 MW in
1990 to almost 13,000 MW in 1996. According to the U.S. DOE, the peak load
reductions of all DLM together has, since 1992, been consistently surpassed by the peak
load reductions associated with energy efficiency and time-of-day rate programs together.
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Actual Peak Load Reductions (MW)
Year
Direct Load
Interruptible
Energy Efficiency &
Total
Control
Load
Other
1990
3692
4219
5793
13,704
1991
5093
4674
6852
15,619
1992
3779
3579
9847
17,204
1993
3955
6628
12,486
23,069
1994
4179
6743
14,079
25,001
1995
5352
8401
15,807
29,561
1996
5575
7390
16,928
29,893
Table 1: Reported Peak Load Reductions for Electric Utility DSM Programs,
1990-1996 (Source: Energy Information Administration, Form EIA-861, Annual
Electric Utility DSM Report”, 1998)
The characteristics of direct load control and interruptible/curtailable programs are as
varied as the utilities that operate them. In fact, historically the first utilities with
ambitious load control programs were co-ops and other small distributors who purchased
power from G&T utilities under a ratcheted demand bulk power tariff. These utilities
pursued DLM not so much for system peak load relief but for minimizing their bulk
power purchase requirements.
Table 2 shows some of the same aggregate data as in Table 1, but this time sorted by
utility class of ownership. Investor-owned utilities predominate, but the early role of
cooperatives in establishing the importance of DLM is clear.
Year IOUs
1990
1991
1992
1993
9435
10,576
12,330
16,362
Historical Actual Reductions, MW
Publicly
Cooperative Federal
Owned
s
1197
1822
1250
1634
2821
588
1794
2374
707
1898
2327
2481
US Total
13,704
15,619
17,204
23,069
Table 2: Peak Load Reduction 1990-1993 by Class of Ownership
(Source: Form EIA-861 data for 1993)
(Includes all DSM Programs – DLM, Energy Efficiency, & TOU)
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Almost any end-use can and has been subjected to some form of load management.
Utilities typically seek out those end-uses whose size and coincidence with system peak
makes them attractive targets. Many utilities have a mix of residential and nonresidential
programs, employing both direct control and interruptible/curtailable approaches. Some
large utilities, such as Duke Power, have well over 1,000 MW of peak load under control
or contract. The section below entitled “Utility Leaders in DLM” provides numerous and
typical examples of both direct control and interruptible/curtailable schemes in current
use.
Like any DSM program, every DLM program design has common elements and shared
hardware requirements. At a minimum, a DLM program must incorporate:
 Head-end system for dispatching and coordination with system dispatchers
 Communications Net (one-way or two-way)
 Receivers
 End-use controller
 Measurement & Verification system
Importantly, the same communications and remote devices used for demand-side load
management can also be used for distribution system management applications, such as
capacitor controls, switches and reclosers, and so on. A section below on vendors briefly
describes some of the leaders in DLM systems hardware and software development.
3. Key Findings
After almost a decade-long period of dormancy, DLM is entering a period of rapid
technology and new product development. This development is being driven by several
factors, most of which have emerged just recently:







New economic incentives for dispatchable load management, created by price
volatility in bulk power markets;
Renewed concerns about the availability of generation during system peaks;
Transmission & Distribution congestion in the linkages between supply and demand;
Improved economics for automatic meter reading and two-way communications
brought about by price reductions and new demand for high-volume data
transmission of all sorts, including interval metering and submetering;
New opportunities for two-way utility-customer communications and interaction
using the internet;
Increased familiarity with aggregation schemes, not only for commercial/industrial
customers but for residential customers; and
A new and aggressive breed of energy-internet entrepreneurs actively pushing the
envelopes of both load management applications and technology.
The contrast between old-model DLM and new-wave DLM is illustrated in Table 3 for
three key customer segments – residential, commercial, and industrial.
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The old-model or traditional DLM approaches are still very common and quite
functional. However, the “next generation” of DLM is more interesting and may be more
adaptable to the applications and objectives that BPA is interested in.
Customer
Segment
Residential
“Old Model” or
Traditional
DLM
Air Conditioner
Load Control
Examples
“Next Generation”
DLM
Examples
FPC, SMUD,
many others
Internet-based
Puget Sound
interactive thermostat Energy pilot
set-point control
project
Commercial
Voluntary Load Duke,
Utility-operated,
Cinergy’s Call
Buildings
Curtailment to
SDG&E, many Internet-based
and Quote
preset Firm
others
system for posting
programs
Service Level
price-call quotes and
processing customer
offerings of load
reduction blocks
Industrial
Industrial Load
Many ongoing Interactive systems
NSP’s “Peak
Facilities
Shedding
non-firm rate
for allowing
Day Partners”
programs
customers to offer
program; Duke
standby generation or Power’s
load shedding at
Standby
daily or hourly sellGenerator
back rates
program
Table 3: Examples of “Traditional” and “Next Generation” DLM Measures
There are several ways in which the new DLM offerings differ from traditional DLM:





They are interactive. The customer interacts with the utility in some way, either via a
utility-hosted web page or some other two-way posting system.
They vary in real-time or almost real-time. The programs are updated daily or even
hourly and reflect schedules and prices that are hourly.
They rely heavily on monetary/economic incentives for inducing customer behavior
and thus can be operated on a non-emergency (and much more frequent) basis.
They are less blunt, less intrusive, and relatively surprise-free compared to the old
direct control programs. The control is via an intermediate vehicle such as a
thermostat or via starting up a customer’s standby generator.
They are more complex and structured such that there are several players involved. In
the Puget Sound Energy example there are four players – Johnson Controls,
manufacturer of the SmartStat; CellNet, vendor of the wireless communications
systems; Silicon Energy, system integrator and software provider; and Puget Sound
Energy, the retail provider who manages the customer relationship and system load
requirements.
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These “next generation” DLM programs are described in more detail in the following
four sections:
 Utility DLM Program Descriptions
 Capsule Equipment & Services Vendor Descriptions
 Capsule Descriptions of Pertinent Literature
 Capsule Descriptions of selected DLM Programs
4. Utility DLM Program Descriptions
Some electric utilities have historically been the most active with regards to dispatchable
load management. Table 4 below shows the top 10 most-active load management
utilities, based on data submitted to the US DOE Energy Information Administration
Company
TVA
Florida Power
Corp
Duke Power
Residential LM Assets
60 MW
850 MW space & water heat
500 MW air con
500 MW EWH & air con
Florida Power &
Light
Northern States
Power
Detroit Edison
Carolina P&L
900 MW space, EWH, & air con
Pacific G&E
Minnkota Power
Coop
Minnesota P&L
250 MW space heating, EWH, &
air con
160 MW EWH load control
250 MW EWH & air
conditioning
Commercial/Industrial LM Assets
1800 MW interruptible/curtailable
400 MW interruptible/curtailable
Total
1860 MW
1750
800 MW standby &
interruptible/curtailable
1300 MW
900 MW
550 MW interruptible/curtailable
800 MW
500 MW Interruptible
400 MW interruptible/curtailable
660 MW
650 MW
200 MW space heat, EWH
505 MW interruptible/curtailable
100 MW ag pump control
505 MW
300 MW
40 MW space heat, EWH
200 MW interruptible/curtailable
215 MW
Table 4: Ten Largest Load Management Utilities
(Source: Energy Information Administration, Form EIA-861, Annual Electric
Utility DSM Report”, 1998)
. As part of this literature and technology review effort we were able to contact half of
these industry leaders. Brief descriptions of their activities and thoughts on the future of
DLM are provided below.
4.1. Northern States Power (NSP)
Northern States Power is a summer-peaking utility that has been active in dispatchable
load management for many years. NSP currently has about 800 MW of peak load under
control. About 250 MW is conventional residential air conditioner load switches, which
are dispatched by the system operator on high-cost or low-reserve days. The balance of
load controlled is Commercial/Industrial programs, of which there are 3000 who
participate in a curtailable/interruptible tariff program. These customers receive a yearround discount on their bills in exchange for reducing their load below a preset Firm
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Service Level. The program is voluntary and the customers have complete flexibility in
terms of what actions are taken to reduce below their FSL. [Respondent: Ralph
Dickinson, (612) 330-6973.]
NSP is also experimenting with a new program, tentatively titled “Peak Day Partners”,
which would provide a “pay-for-performance” option to C&I customers who could “sell
back” additional load blocks beyond their reduction to FSL for a variable $/MWH price.
NSP is teamed with Silicon Energy and will be using their software product “Curtailment
Manager” in this program. [Respondent: Ralph Dickinson, NSP Load Management
Supervisor, (612) 330 6973.]
4.2. Florida Power Corporation (FPC)
Florida Power Corp. is a long-time industry leader in the area of dispatchable load
management. They had one of the largest air conditioner control programs for most of the
1980’s. In 1998 they used their program extensively as the summer was quite hot and
supply resources were stretched very thin.
The resource in place at the moment is 475,000 residential customers with a capacity of
850 MW of strip space heaters and electric water heaters. They have historically had a
winter peak consisting of big demand spikes on the occasional extra-cold winter morning.
FPC uses a shed strategy on 10 different load blocks to obtain load relief.
More recently they have had a summer peaking problem which has motivated them to
install some 500 MW of residential air conditioner load control. Customer thermal
sensitivity due to the hot and humid southeastern climate restricts their air conditioner
load control to cycling on a 33 % to 55 % duty cycle.
Carolina P&L recently been acquired FPC. They are currently looking at their programs
to see how they might fit in the new deregulated world. They are using their program in
the traditional way and have experimented with using this resource both for T&D (local
or network) load relief and also for economic dispatch. However, they are still also bound
by regulatory considerations governing DSM, which has its own regulations on use and
cost recovery.
They also have interruptible and curtailable projects. The interruptible focuses on blocks
of load 500 kW or larger, while the curtailable is voluntary with a firm service level. Lots
of the interruptible industrials have stand by generation. This represents another 400 MW
of load available summer or winter. [Respondent: Dan Christopher, (727) 518-3601.]
4.3. Cinergy
Cinergy has two different and very innovative programs for their commercial and
industrial customers.]. They have done real time pricing for about three years now to
these customers. They have had 300 customers on Real Time Pricing (RTP) for several
years. They have achieved really good price responsiveness, indicating that these large
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customers are receptive and ready to respond to price variability if it is properly
communicated to them.
Cinergy has a brand-new program called Power Share. [Promotional materials appear on
their website – www.cinergy.com.] There are two key features built into this new
scheme: call options and quote options. In a call option the customers make a committed
response: they must either reduce load or run their generators to make up the difference
in their commitment.
They can get paid in two different ways for their performance after a call option – via an
energy credit on their bill or by sharing the overall market credit that Cinergy realizes as
a result of spot power market plays.
Committed responses are necessary in order to participate because the customer
reductions are considered by Cinergy to be physical hedges and therefore they must be
firm blocks of load.
Another new program is the “Quote” program. This is being offered to both existing RTP
and non-RTP customers. It works like this:
 Cinergy will post a price quote and time schedule for load reduction on their Internet
site at 8 in the morning. The participating customers can go to the web site and
indicate how much load relief they can provide at that price quote.
 By 9 am customers must commit to providing a certain level of load relief on a
certain schedule. If they do commit then Cinergy provides a pro forma load shape for
that customer to access. [Cinergy has a program that estimates for each customer
what they think the normal load shape would be, given the forecast temperature and
customer billing history.] The load shape for the eight-hour period that Cinergy
provides becomes the benchmark for what the customer can do and how they will be
compensated for their performance.
The program is designed to be risk-free to the participant. If the customer’s load is above
the pro forma load shape benchmark, there is no penalty; if it is below the load shape the
customer is compensated based on the price quote provided that morning.
Cinergy is actively marketing both programs to their mid-sized and larger C&I
customers. The target is to attract up to 500 customers of 1 MW and greater and sign up
as much as 250 MW on the program over the next two years. [Respondent: Harry Darnell
of Cinergy, (317) 838-1891.]
4.4. Duke Power
Duke Power Corporation has been in the dispatchable load management business for a
very long time. Duke has a very mature VHF-based 1-way radio system covering their
entire service territory. They purchase switches from both Cannon Scientific (formerly
ABB Controls) and Comverge (formerly Scientific-Atlanta).
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Duke’s DLM philosophy is to utilize this resource expressly in servicing their native
load, protecting the Company against wild price swings, and as a last-resort hedge against
supplier defaults in physical delivery.
This last contingency is a real concern after the price spikes and trader defaults of last
summer. Whether these wholesale supply reliability problems are transitional or not is
uncertain; however, it is clear that there is a window where meeting native load at peak
may be difficult and therefore the value of DLM is particularly high.
Historically, Duke has made it a policy not to call for the DLM program unless there is a
real power shortage emergency - and then use it to control or shed all loads necessary to
restore stable and reliable operation. This has served their public relations and customer
acceptance objectives well, as DLM operations are generally accompanied by newspaper
and radio announcements.
Their program is so mature that they hardly ever even test it anymore. On an ideal day
Duke will have about 500 MW or peak load reduction available from about 400,000
residential air conditioners and electric water heaters.
Duke also has an industrial curtailment system consists of two rates: interruptible service
rate and a standby generator program, which involves a device in the field. The industrial
curtailment program is traditional: they send a signal to customers, who then have 30
minutes to reduce load down to their preset firm service level.
There is a big penalty for noncompliance.
Regarding noncompliance, another Duke operating philosophy has been to always
actively audit their programs and participants. Most curtailment systems are just
messaging systems, not real two-way curtailment systems. Duke has installed RTUs on
all curtailable customers so they have indisputable data for administration of the program.
They also have a standby generator program. This works via an alert relay tied to the
generator, which spools up the generator in advance of curtailment notification. This is a
pay-for-performance scheme, where the customer is actually paid for the kWh they
generate. This is a very popular program, as Duke will come in to test and maintain their
generator program and provide reports to management and regulators that the customer
would otherwise have to themselves provide. Duke believes this is a very promising
program that could be significantly expanded. At present only 60 MW is obtained from
the standby program.
Duke has over 800 MW available in the combination of standby generation and
interruptible/curtailable. These programs are all generally used when purchasing power is
more expensive than their most expensive owned-unit.
Both the residential program capacity and the standby generator capacity can be
substituted for spinning reserve, as they are instantaneously dispatchable and have a real
energy component.
Page 8
Duke has a very large DLM effort, and the Company feels that the reliability benefits as
well as avoided generation capacity costs is more than large enough to offset the costs of
this system.
Duke is looking at some new voluntary programs involving energy and demand buybacks. A corporate directive has been established to avoid buying super-expensive spot
power in order to meet native loads. Duke is also thinking through its overall strategy for
the future of both residential and nonresidential load management systems. Duke is
convinced that both of these programs have an important ongoing role to play in system
operations, especially during this transitional window. [Respondent: Tom Bingerheimer,
(704) 382-6957].
4.5. Great River Energy
Great River Energy is a publicly owned utility located in Elk River Minnesota. They have
been in the load management business for 20 years. Their experience spans the range
from air conditioner and irrigation pump control to automatic start up of backup
generation.
With a system peak of 2000 MW summer peak, Great River has 250-300 MW of load
under control, including 80 MW of curtailable load and standby generation, 45 MW of
irrigation pumps, 70 MW of residential air conditioners, plus some 30 MW of electric
water heaters and some voltage control. They have a 7 PM summer weekday evening
peak, so their water heater load has a 0.7 coincidence factor.
They also control in the wintertime and have almost 200 MW of dual-fuel space heaters
under control as well.
Last year with the crazy volatility in prices they used their system to avoid expensive
energy purchases in addition to avoiding expensive demand charges. A program that they
built for capacity is also available – within reason – for energy as well.
[Respondent: Roger Rognli, Great River Energy, (612) 241-3714.]
5. Equipment & Services Vendor Descriptions
The dispatchable load management equipment manufacturing and services industry is
small and centralized. It is dominated by a handful of small firms catering to the
traditional DLM market plus a very few start-up companies just beginning to capitalize
on the new ideas entailed in “next generation” DLM concepts. Note that there is a
separate and much larger building controls and energy management systems industry,
including such giant firms as Honeywell and Johnson Controls, which was not included
in this vendor survey.
5.1. Cannon Technologies
Page 9
Cannon Technologies has been in existence for 12 years, and recently bought ABB’s
entire utility load control systems division. They now have a broad product line and many
long-standing customers. Their product offerings include a whole series of remote control
devices (load control receiver, distribution line carrier receiver, capacitor bank controller,
& metering devices) all of which communicate via Motorola’s 900 MHz FLEX paging
technology. Altogether, Cannon claims to have 5,000 MW of load under control with its
devices around the country.
Cannon also provides software and services to utilities implementing or operating DLM
programs. They are quite actively developing new product concepts that can provide
value-added services such as remote meter reading, outage paging services, appliance
repair referral services, etc. They have provided a very handy reference book entitled
“Traditional and Nontraditional Methods for Marketing Load Management’.
[Respondent: Ed and Joel Cannon, (800) 827-7966.]
5.2. Comverge Technologies, Inc.
Comverge is a spin-off of Lucent Technologies that purchased the control system
division of Scientific-Atlanta’s business. Their first mission was to re-establish the brand
name of Scientific Atlanta. They had manufactured 5 million load control devices and
served some 300 utilities. Their products and applications include: Direct load control,
capacitor bank control, distribution management control, interruptible metered services,
irrigation controls, and other dispatchable loads that utilities operate. Some newer
products include “Gateway Products”, which allow the utility to offer a service that
engages the customer in some fashion. Spot pricing, TOD, load shedding, energy
management interfaces are examples of these. Gulf Power is a big client, purchasing
“main gate” products for their residential RTP-TOU program.
Comverge also has a number of other special programs:

Outage management -- This program includes a life safety program and
supervisor notification via wireless communications.

Metering communications --Wireless, low-cost transport of interval metering data
in real time using cellular CDPD. The CDPD technology allows you to use the
Internet to interrogate over the wireless system. This is very new technology,
mostly available in urban areas.

Customized Theft detection -- using powerline carrier & interval meters.

Residential thermostat control --City of Austin has awarded them a contract for an
intelligent thermostat called a SuperStat. GPU already has one of these programs.
Honeywell is the developer of the thermostat; Scientific Atlanta developed the
intelligence and the communications gateway. One function might be remote
utility control of thermostatic setpoint or setpoint strategies such as precooling.
[Respondent: Dick Preston of Comverge,(888) 991-8033.]
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5.3. Silicon Energy
Silicon Energy is a recent start-up company that bills itself as “the global leader in
Enterprise Energy Management”. Located in Alameda, California, they have several
important industry alliances in place with Planergy Services, Inc, CellNet Data Systems
Inc, and others.
Silicon Energy has an excellent web site, www.siliconenergy.com, which contains
several press releases and articles, and served as the source for the information below.
The much-talked-about Puget Sound Energy project will involve 200 PSE customers who
will give the company permission to remotely make slight adjustments to their
thermostats, thus reducing energy usage during peak use periods. Unless over-ridden by
customers, the thermostats will adjust the set point in the home by up to six degrees for a
period of no more than four hours. In addition, electric water heater operation will be
disabled during the control period to increase the demand reduction. The actual
temperature of the house will be transmitted back to the utility and posted on a web site
that the customer can access. Customers access the web site with a password and can then
remotely check the indoor temperature and adjust the set point at any time.
In a separate project Silicon Energy and Planergy Services have joined forces to provide
“integrated load curtailment solutions” for utilities and power brokers. The alliance is
based on a product called the PowerLinkWeb, which allows participating customers’
direct access to submetered load information on their facility. The software also allows
utilities to very accurately predict what the load shape of a particular customer is likely to
be on a given day, based on billing history and forecast temperature and other factors.
This capability affords both the utility and the customer a “benchmark load shape” that
both can use to predict the load reduction available and plan, implement, and monitor the
actual strategies the customer pursues to obtain this load relief. [Respondent: Allan
Schurr, (510) 749-940.]
6. Capsule Descriptions of EPRI Literature
EPRI and the IEEE PES Transactions were the two most abundant sources of reports
and studies of dispatchable load management throughout the late 1980’s and into the
1990’s. EPRI in particular did much of the organizing if not the formative work. Among
the reports which are still quite useful:

“Proceedings: Load Management Conference. Dynamic DSM Options for the
Future”, EPRI Report TR-105422, August 1995.
This was probably the last major conference focused on load management before the
recent resurgence of interest in the topic. This Proceedings includes 35 papers from a
diverse group including top utility executives, regulators, equipment manufacturers,
system developers, consultants, and utility DLM program managers. Included are
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retrospective papers on the load management industry experience as well as inklings
of the technology that is now driving the “new-wave” DLM program.

“Customer Backup Generation: Demand-Side Management Benefits for Utilities and
Customers”, Report CU-7316, Jul 1991
Published in the heyday of DSM and load management, this report reviews the
opportunities for beneficial additions of backup generation at selected high–outagecost customer sites. Customers benefit through increased reliability and lower rates on
interruptible service options. Utilities benefit from having a reliable peak-clipping
resource. The report introduces the concept of quantifying customer outage costs
describes customer segments with a likelihood of high outage costs. It describes
backup generation and dispatch technologies and their costs and provides analysis of
costs and benefits to customers and utilities of a backup generation program. Also
included is a useful listing of C&I nonfirm rate programs.

“Customer Response to Rate Options”, Report CU-7131, January 1991.
This report brings together and summarizes several years of research and
development on customer response to rate options. It describes and discusses how to
apply EPRI tools such as RELIEF, RETOU, and CIRTOU in the analysis of customer
response to a variety of rate options including TOU, incentive rates,
interruptible/curtailable programs, and RTP. Numerous examples based on real utility
programs are presented and generic results described.

“Customer Response to Interruptible and Curtailable Rates”, Report EM-5630, March
1988 (vols. 1 and 2).
This is an excellent reference for anyone interested in the expected performance of
interruptible/curtailable rate programs from a load impact viewpoint. The actual
operating results of numerous then-existing interruptible/curtailable programs were
obtained and used to construct several models for estimating customer responses to
interruptions. The performance of these models is then compared, as are the results
obtained from the participating utility programs.
Much of the specific discussion of interruptible and curtailable rates contained in
Section 9 of this Report were taken from this source.

“Application of Interruptible and Curtailable Electric Service in Foundries”: CMP
Report No. 95-2, EPRI Report No. CR-105046, March 1995.
This brief (50-page) report presents a practical method to evaluate the savings
potential of interruptible and curtailable electric service for foundries. The study was
commissioned because although foundries with their batch processes should have a
high potential for nonfirm rates, the realization of this potential has been impeded by
Page 12

 a lack of utility knowledge regarding the effect of power interruptions on quality
and productivity
 a lack of knowledge by foundry personnel regarding the rates available and how
they might be applied.
“Priority Services Design and Forecasting Project: Priority Service Methods at
Commonwealth Edison”, Report TR-101431, Dec 1992 (200 pages), and Priority
Services Design and Forecasting Project: Priority Service Methods at Union Electric
Co., Report TR-101430, Dec 1992 (188 pages).
Both these reports were the products an overall EPRI effort called PRISM, or Priority
Service Methods. These reports define priority services as programs like interruptible
service that allow a utility to share control of electricity use with customers. The
rationale for this work was to better understand customer preferences for electric
service and then offer rate options that provide a better match to customer needs. In
this study, surveys of actual customers were used to evaluate the performance of the
Union Electric (UE) “Controlled Energy Services” rate option, and to determine
potential for future priority services.
The study of Commonwealth Edison customers tested the validity of previously
developed models of customer response to controlled energy services; developed a
more cost-effective, computerized survey technique; and estimated customer
acceptance of various controlled energy services.
Both these reports are useful updates on the range of program variables than can be
designed into an interruptible rate – such as notice period, length of interruption,
frequency, incentive levels and how they are designed into the rate, etc.

“Transmission and Distribution Benefits of Direct Load Control: Seattle City Light
and Snohomish Public Utility District Pilot Project Evaluations”, Report TR-103993,
Feb 1995, (216 pages).
This report describes two separate but similar residential electric water heater direct
load control programs in the Puget Sound region. The programs were Seattle City
Light’s Peak Energy Program (PEP), and Snohomish PUD’s Water Heater Peak
Savers Program (WHPSP). As part of a larger series of studies of the T&D benefits
of DSM, during the winter of 1993-1994 both programs were configured to yield
peak load reduction at both the system as well as the local transmission and
distribution level. This report presents program load impact results estimated using
metered and disaggregated end-use load data. Also included is a detailed description
of participants' attitudes toward the programs and their experiences with program
implementation. There is enough detail in this report to design a successful residential
electric water heater load control program.

Additional EPRI Reports Applicable to this Project:
Page 13
(a) “Residential Load Management Technology Review”, EPRI EM-3861 Final Report,
February 1985 (340 pages). Prepared by Analysis and Control of Energy Systems,
Inc.
(b) “Impact of Demand-Side Management on Future Customer Electricity Demand: An
Update”, EPRI CU-6953, September 1990 (100 pages). Prepared by BarakatChamberlin Inc..
(c) “Integrating Demand-Side Management Programs into the Resource Plans of U.S.
Electric Utilities”, EPRI TR-100255, December 1991 (86 pages). Prepared by Oak
Ridge National Laboratory.
(d) “Residential Load Control and Metering Equipment: Costs and Capabilities”, EPRI
EM-5392, October 1987 (45 pages). Prepared by ELECTROTEK Concepts Inc.
(e) “Fundamentals of Load Management: An IEEE Tutorial Course”, October 1988 (50
pages). Prepared by the IEEE Power Engineering Society DSM Subcommittee.
(f) “Impact of Direct Load Control Programs: A Duty-Cycle Approach, volumes 1 and
2”, EPRI CU-7028, December 1990. Prepared by Quantum Consulting, Inc.
(g) “The Performance Potential of Local and Distributed Load Controllers”, EPRI CU6632, March 1990 (140 pages). Prepared by Analysis and Control of Energy Systems,
Inc.
(h) “Control Strategies for Load Management”, EPRI EM-3882, July 1985 (62 pages).
Prepared by Roger D. Levy.
(i) “DSM Customer Response, Vol. 1: Residential and Commercial Reference Load
Shapes and DSM Impacts”, EPRI EM-5767-V1, June 1988 (344 pages).
(j) “Field Performance of Residential Load Controllers”, EPRI EM-5955, August 1988
(288 pages).
(k) “Industrial Load Shaping: An Industrial Application of Demand-Side Management,
Volume 1: Overview”, EPRI CU-6726-V1, June 1990 (64 pages).
7. Other General Literature and Reports Worthy of Note
As part of this project we undertook a thorough search of bibliographic and full-text
databases covering the scientific literature (journals, conference papers, government
publications) as well as trade and business publications. This search yielded a number of
additional citations from literature including NTIS, the IEEE Power Engineering Society
Transactions, the Agricultural Engineering Journal, and others. The most useful citations
found and reviewed are abstracted below:
Page 14

“Annual Report on U.S. Electric Utility Demand-Side Management”, 1996. USDOE,
Energy Information Administration. This is an annual report produced by the USDOE
and the EIA in conjunction with Oak Ridge National Labs (ORNL). This report
presented the results of data from the utility industry as collected by Form 861, a
mandatory data collection instrument which focuses on utility-sponsored demand-side
management ,programs and their demand impacts, energy savings, and cost. There is
a chapter dealing specifically with peak load reductions of DSM programs which
contains data by utility specifically on the impacts of each program type – energy
efficiency, direct load control, interruptible, and “other”. This report was the source
of the data contained in Tables 1, 2, and 4 above. This report is available of the EIA
web page, www.eia.doe.gov.

“Load Impacts of Interruptible and Curtailable Rate Programs: Evidence from Ten
Utilities”, D. W. Caves, et al, Christensen Associates. IEEE Transactions on Power
Systems, v. 3 # 4, November 1988. This paper reports on the results of a two-year
study of industrial and commercial response to interruptible and commercial response
to interruptible/curtailable (I/C) tariff programs. The project draws on
data from ten utilities and 147 customers with I/C service. A statistical procedure
for measuring the load relief obtained from an interruption is outlined and
compared to techniques based on average demand and day matching. Estimates
of load relief are then presented for the ten utilities. While the estimates
indicate that customer compliance is generally good, a significant disparity is
found between the measured load relief and the load relief used to award customer
credits.

“Distribution Substation Load Impacts of Residential Air Conditioner Load Control”,
Grayson Heffner, et al, PG&E. IEEE Transactions on Power Apparatus and
Systems, Vol. PAS-104 # 7, July 1985. This useful paper reports on PG&E’s efforts
to measure the substation-level aggregate impacts of air conditioner load control
strategies of various types, including load shedding and cycling.

“Residential Air Conditioner Cycling: A Case Study”, G.F. Strickler, et al, Southern
California Edison. IEEE Transactions on Power Systems, v. 3 # 1, February 1988.
This is another useful paper on a real-world program with empirical results for air
conditioner load control in southern California.

“Standby Power Generation under Utility Curtailment Contract Agreements”,
Gregory Nolan, et al, Stone & Webster Engineering. IEEE Transactions on
Industry Applications, v. 33 # 6, Nov/Dec 1997. Many utilities in the United States
offer large industrial and commercial customers power sales contracts, which have
attractive rates under a curtailment requirement. This paper reviews the alternatives
faced by a curtailment contract customer together with potential load shedding and
standby-generation system designs. An example of implementing a curtailment
contract at an existing industrial facility is presented. The example facility, Boeing
Helicopters, Philadelphia, PA, required both load shedding and standby generation.
The load-shedding scheme is fairly complex and is controlled by a programmable
Page 15
logic controller (PLC). The standby-generation and load-shedding systems for the
example facility are examined in detail. Also, lessons learned from implementing the
required modifications to the example facility are discussed.

“Managing the Instantaneous Load Shape Impacts Caused by the Operation of a
Large-Scale Direct Load Control System”, G. Heber Weller, Florida Power Corp.
IEEE Transactions on Power Apparatus and Systems, v. 3 # 1, Feb. 1988. This
paper addresses the real-time operating considerations of a large-scaled direct load
control system from the system operator’s point of view. It specifically discusses the
design considerations that go into the development of load control strategies such as
duty cycling and load shedding. Since this program involved control of residential
space heating and water heating, it is of obvious application to this study.

“Economic Benefits of Appliance Load Control Strategies using DAS”, Hossein
Haeri, Et al, Panalytics Inc. Third International Symposium on Distribution
Automation and Demand Side Management. DA/DSM 93, p.222-30. This paper has a
good discussion of the program design considerations involved in a water heating
direct load control program. The case study is Central Maine Power’s program
involving 13,000 residential customers. The emphasis is on calculating the overall
economic benefits of such a program.
8. Literature and Information Specifically Focused on Agricultural Load
Management
There is not a lot of literature specifically treating agricultural load management. There
are, however, several valuable short note reports prepared by the NRECA (National Rural
Electric Cooperative Association) as well as papers that may be found in the Journal of
the American Society of Agricultural Engineers and the Irrigation Journal. We have
listed below the sources we found most useful in answering key questions regarding the
technical feasibility of agricultural dispatchable load management.
8.1. Listing of Pertinent Agricultural Load Management Literature



“Irrigation Load Management: Options and Opportunities”, NRECA ARC 85-2E.,
1986. Prepared by the National Food and Energy Council for NRECA. This is an
excellent source of general information about irrigation techniques and specific case
studies on how agricultural pump direct load control has been implemented in areas
all over the country, including Wisconsin, Arizona, Nebraska, and the deep South.
“Irrigation Systems Managed by Electrical Load Management”, P.L. Barnes, et al,
Kansas State University. Paper No. 86-2602, presented at the 1986 Winter Meeting of
the ASAE. This paper includes some actual feeder-level results of agricultural pump
control in KAW Valley Electric Cooperative.
“Input Power to Electric Motors for Irrigation”, L.E. Stetson, et al, University of
Nebraska. Paper No. 88-3001, presented at the 1988 Summer Meeting of the
American Society of Agricultural Engineering. Good source of basic information
about the horsepower size distribution of motors in the upper Midwest.
Page 16

“A Recap of Irrigation Load Management Successes and Failures”, LaVerne E.
Stetson, University of Nebraska. Irrigation Association 1985 Technical Conference
Proceedings – “Irrigation in Action”, Nov. 17-20, pp., 24-32. Reports on results of
several pump load control programs, including demand relief and number of hours of
control per growing season.
 “Irrigation Systems in Transition – Center Pivots and Linear Moves”, Irrigation
Journal, March 1994, v. 44 # 2, p. 16-24. This article discusses the latest
technologies in high-pressure sprinkler irrigation and the general trend away from
gated and open channel irrigation.
In addition to this written literature, we were able to make contact with a number of
practicing agricultural engineers and equipment designers, including the following very
helpful respondents:








Doug Backer and Kevin Klau, Cannon Technologies
Larry Liss, Nebraska Public Power District
Roger Simmonson, Minnkota
Roger Rognli, Great River Energy
LaVerne E. Stetson, University of Nebraska (retired)
Dale Heermann, USDA, Colorado State University
Dr. Charles Sopher, EPRI Agricultural Technology Alliance
Fred Zaire, Irz Irrigation Consulting, Hermiston, Oregon
Based on the literature and the telephone surveys we were able to answer the following
key questions which affect any calculation of technical or market feasibility of
agricultural pumping dispatchable load management.
8.2. Key Q-and-A Regarding Technical Feasibility of Agricultural Pump Load
Control

What is the target or threshold size of irrigation and agricultural pumps to be
controlled?
The short answer is 10 hp, as there are very few irrigation pumps smaller than
that. The longer answer is that it depends on the size distribution of the pump
population served by a given utility. In regions with ample surface water the
pumps will be lower head, lower volume, and smaller size. In regions away from
rivers or canals the pumps will be high head, often deep well, and significantly
larger. A case study of Southern Public Power District in Nebraska, contained in
Irrigation Load Management Options and Opportunities, suggests some rules of
thumb:
 Total pumps served: 6,000, representing 151,000 hp of load (average
size: 25 hp)
 Pumps under load control: 2,600 representing 102,000 hp (average
size: 39 hp)
Page 17

What is the availability of the pumping load for control?
This can be expressed as a monthly or seasonal load factor for the pumping loads.
The load factor or availability of an irrigation pump is highly variable and is
dependent on region, cropping patterns, rainfall patterns, and type of irrigation
system. In areas such as Idaho and eastern Oregon, with virtually no rain during
the growing season, you can have very high load factors – as high as 0.9. In other
regions with some summer rainfall (Nebraska), the load factor may be much
lower, perhaps 0.6 or 0.7. Cropping patterns also affect load factor, as some crops
such as alfalfa need constant irrigation while others such as potatoes only need
water during certain critical points in the growing season.
Another important variable is the type of irrigation system in use. Open channel
and gated pipe systems are relatively inefficient, delivering water at low pressure
and in large volumes, which then need to percolate the soil. Sprinkler irrigation is
more expensive to install, but is more efficient, delivering more precise and
uniform amounts of water to larger areas via high-pressure. There is a trend
towards the more expensive, more-automatic sprinkler technologies such as solidset, side-roll wheel-move, traveling gun, center pivot, and linear-move systems.
This trend towards more efficient delivery systems means less connected pump
load overall, but higher load factors for the higher-tech irrigation systems now
being used in greater numbers.
There will never be unity load factors, because there has to be sufficient excess
water delivery capacity to allow for both maintenance and other downtime
necessary to reposition or fine-tune the irrigation systems.

Is pumping on all irrigated crops of equal value or is there something about
corn and potatoes that makes them especially well suited to the program?
The common irrigated row crops in the upper mid-west and eastern Pacific
Northwest include corn, alfalfa, potatoes, and sugar beets. Other grain crops, such
as wheat, oats, and barley, do not have sufficient returns to justify large
applications of water. However, cropping rotation often means that irrigated fields
will have different crops in different years. If the irrigation system is in place,
then it will get some use no matter what the crop is.

How does weather and phase of the growing season affect availability?
Weather variables consist of rainfall and ambient temperature. Ambient
temperature, surprisingly, has little impact on irrigation pumping loads. Several
studies done by NRECA show little or no correlation between temperature and
pumping – except during sustained periods of unusually high temperatures
combined with no rain. Rainfall of course has a very big impact – if it rains, the
pumping load factor falls off dramatically.
Page 18
Irrigation pumping load does vary by the phase of the growing season, but the
nature of the variation depends on the cropping pattern, as well as rainfall as an
intermediate factor. As mentioned above, alfalfa requires almost constant
irrigation throughout the growing season, while potatoes have to be irrigated early
in the season but must not be irrigated during the later part of the season.
There has been some work done by NRECA in conjunction with BPA to develop
schemes of reducing pumping demand during on-peak hours. Eastern Oregon
Farms, now owned by Potlach Industries and located in Boardman, Washington,
had an extensive program to manage peak demand and avoid on-peak demand
charges. One irrigation consultant who is very familiar with conditions in the
BPA service territory is Fred Ziari [Irz Consulting, Hermiston, Oregon (541 567
0252)]. Mr. Ziari offered these additional insights specific to the BPA service
territory:



The proportion of sprinkler irrigation systems is high in the BPA area.
Assume 75 % sprinkler coverage in Washington, 66 % sprinkler coverage in
Idaho, and 50 % sprinkler coverage in Idaho. Generally, sprinkler systems will
have a considerably higher load factor than open channel systems.
The individual pumping loads are very large – many 5 MW pumping stations,
especially in the Columbia River Basin, with a very large number of 1 MW
pumps.
The pumping season starts as early as March in Eastern Oregon and
Washington. March-April-May and September-October are shoulder months,
with June-July August being the peak months. During the peak months a
typical irrigation set will run six out of seven days. A load factor of 0.9 for the
peak months and 0.6 for the shoulder months would represent this pattern.
9. Literature and Information Specifically Focused on Commercial and Industrial
Non-firm Rates
The following literature was reviewed in detail to better understand the technical
potential for commercial and industrial interruptible/curtailable load-management
programs:
1. Customer Response to Interruptible and Curtailable Rates, EPRI EM-5630,
March 1988.
2. Load Impact of Interruptible and Curtailable Rate Programs: Evidence from Ten
Utilities, IEEE Transaction on Power Systems, v. 3 # 4, November 1988.
3. Standby Power Generation under Utility Curtailment Contract Agreements, IEE
Transactions on Industry Applications, v. 33, # 6, Nov/Dec 1997.
4. Factors Affecting Large Industrial and Commercial Customer’s Participation in
Interruptible and Curtailable Rate Options, PG&E Internal White Paper, 1985.
5. Customer Response to Rate Options, EPRI CU-7131, January 1991.
6. Customer Back-up Generation: Demand-Side Management Benefits for Utilities
and Customers, EPRI CU-7316, 1991.
Page 19
The first reference is by far the most comprehensive, and includes an extensive
discussion of the variables which affect both customer participation in a non-firm rate
and the amount of load relief that can be realized with various rate designs and from
different customer types. Both this reference and Reference 2 describe the only crossutility study of interruptible/curtailable (I/C) rates performed, utilizing data from 148
customers on I/C rates offered by 10 different utilities.
9.1. Key Rate Design Variables
The biggest challenge in analyzing I/C rates is developing an understanding of how key
rate design variables and customer characteristics affect the two most important program
results – customer participation rates and selection of the Firm Service or Firm Power
Level (FPL). Key design variables and customer characteristics include:
 Load factor
 Number of interruptions
 Length of contract
 Level of credits
 Penalties
 SIC code
The attached figure, taken from Reference 1, shows some quantitative results from the
ten-utility study.
The following are general guidelines for identifying the technical and market potential of
interruptible and curtailable rates for commercial and industrial customers:




Minimum Customer Size. This is expressed as minimum curtailable load. Ten of the
14 individual programs analyzed in Reference 1 had a minimum curtailable load
requirement of 500 kW. The programs with no minimum curtailable load requirement
all had a minimum customer maximum demand requirement of 500 or 1000 kW.
Suggest you use 1 MW maximum customer demand as a cut-off point for all the I/C
options you analyze and a 500 kW minimum curtailable load.
Contracted Frequency of Interruptions. Various tariffs provide frequency limits in
terms of interruption hours per year, per week, and per day, and interruption events
per day and per year. The rough average specification across the ten-utility study was
no more than 8 interruption hours per day, n more than 200 total interruption hours
per year and no more than 25 interruption events per year.
Advance Notification. Many programs distinguish between “normal” and
“emergency” operations. The emergency proviso allows for the utilities,
instantaneously or on very-short (10 minutes) notice, interrupt load. The advance
notification during normal operations varied from 30 minutes to 24 hours. The
average “normal operations” advance notification period across the programs was 1
or 2 hours.
Subscription Period. Most of the utilities required that a customer sign up for a
minimum of 2-3 years.
Page 20
Reference 1 also contains descriptive statistics on the characteristics of customers
participating in the programs. These descriptive statistics indicate that over well over half
of the participating customers are in four SIC codes: Chemicals & Allied Products (28),
Stone, Clay, Glass, & Concrete (32), Primary Metals (33), and Fabricated Metal Products
(34). Over half of the participating customers had average demands of 2 MW and
greater. Half of participating customers had load factors greater than 60%.
Reference 1 (provided to SBW in its entirety) also presents a complete regression
analysis method for modeling the customer response to an interruption. The data
available from this modeling effort makes it possible to directly use some of the results
from these ten utility programs to answer the questions you have posed. Table 5 below
characterizes the key utility program experiences we will use to response to SBW’s
questions.
There is additional more-detailed customer preference information available from
Reference 4. Although this preference data is specific to PG&E, it can be used to
characterize commercial/industrial customers elsewhere. The market research in
Reference 4 was done with specific reference to the PG&E non-firm rate structure and
the results are summarized in Table 2 below. Two statistically representative samplings
of commercial and industrial customers were asked to choose among seven different
levels of service, from Firm Service to Interruptible C. The OPS-1 group consisted of
customers already taking non-firm service, while the OPS-2 group consisted of customers
who had no experience with non-firm service. The customers were sorted by major SIC
division and their responses noted. I have ordered these responses below in order of low
to high severity (and small to large incentive).
9.2. Defining Generic Interruptible/Curtailable Program Characteristics &
Participation Rates
Table 3 attempts to provide as detailed a specification as to an ideal nonfirm program as
is possible considering the paucity of information in this area. Specifically, for each of
the industrial and commercial groups we attempt to extract from the literature the
following:
a) SIC codes that participate
b) Facility load and controlled load thresholds
c) Percent of total facility load controlled
d) Control period duration and frequency limitations
e) Payback (what happens to the customers load shape?)
In Table 3 we have used the values from Table 2 plus Reference 1 to identify the sectors
and SIC codes where customer participation could be reasonably expected. The average
values from Table 1 have been used to characterize the likely average customer size and
amount of load reduction possible for each of the generic nonfirm options identified. All
indications are that the manufacturing sector, especially 2-digit codes 28-34, are most
likely to participate in both interruptible and curtailable programs. The number of
customers likely to choose the different options defined could be further implied by using
Page 21
the numbers in Table 3. However, Table 3 is for current non-participants; participants in
non-firm rate programs are much more bullish on the advantages and less concerned
about the disadvantages. In Reference 4, Table IIIA-3 there are figures showing that 71%
of respondents who are currently on non-firm rates are in SIC Codes 20-39. Another 13%
are in SIC Codes 70-89 and only 6% each are in SIC Codes 10-19 and 50-59.
Based on anecdotal knowledge we have also tried to fill in the SIC codes likely to be
interested in the two generic standby programs identified.
Page 22
Utility/
Program
Type
Notification
Period
Frequency
Of
Interruption
Total
Interruption
Hours
Estimated
Avg Load
Per
customer
(MW)
APCO/
Curtailable
PG&E/
Curtailable
24 hours
None
30.1
1 hour
40 per year
PG&E/
Interruptible
30 minutes
normal/10
min.
emergency
30 minutes
40 per year
40 per week;
600 per year
8 hours per
day; 320 per
year
8 hours per
day; 320 hours
per year
1
hour/Instantan
eous in
emergency
No restriction
150 hours per
year
No restriction
GPU/
Curtailable
NSP/
Interruptible
20 per year
Estimated
Avg Load
Relief(MW)
(Percent of
Load
Interrupted)
13.
(46%)
3.76
(60%)
Customer
Compliance:
Percent that
Comply by
reducing load
3.7
7.9
6.3
3.71
Payback/
Recovery
Observed?
60%
Customer
Compliance:
Percent not
required to
reduce load to
comply
17%
58%
18%
No
3.5
(94%)
46%
1%
No
1.84
(23%)
3.69
(99%)
44%
52%
No
81%
0
Yes
Yes
Table 5: Average Customer Size, Average Load Relief, Compliance Levels for five Interruptible and Curtailable Programs
(Source: Reference 1
Page 23
Nonfirm Rate
Designation
Notification
Period
Frequency
of Operation
Ag/
Forestr
y
Mining/
Constr
Mfg.
Trans./
Utilities
WholeSale/
Retail
20-39
40-49
50-59
58
33
3
3
3
76
8
38
62
10-19
01-09
Firm Service
Curtailable A
Curtailable B
Curtailable C
Interruptible A
Interruptible B
Interrupible C
Totals
N/A
60 minutes
30 minutes
10 minutes
60 minutes
30 minutes
10 minutes`
N/A
8 per year
15 per year
40 per year
8 per year
15 per year
40 per year
50
38
38
38
12
12
Finance,
Ins,
Real Estate
60-69
29
43
14
14
8
Svcs
Public
Admin.
70-89
90-99
53
29
6
6
6
34
33
33
12
100%
100%
100%
8
100%
100%
Table 6: Commercial/Industrial Market Preferences for Various
Firm and Nonfirm Rates (Source: Reference 4)
[In % Expressing Preference for Each Rate Option]
[Customers not currently on Non-Firm rates]
Page 24
100%
100%
100%
Nonfirm Rate
Category
Notification
Period
SIC Codes/
Building
Types
Likely to
Participate
28-34
Average
Facility Total
Load
(MW)
Avg percent
of Facility
Load
Controlled
Average
Firm
Service
Level
Control
Period
Duration
Limits
Frequency of
Control
Limits
Payback
Characteristics
Industrial/
Interruptible
Industrial/
Interruptible
Industrial/
Curtailable
Industrial/
Curtailable
Commercial/
Curtailable
Standby Generators
– utility controlled
(instantaneous)
Standby Generators
–
Customer controlled
(one hour lag)
10 minutes
3.7
100%
0
8 hr. per day;
320 hr. per yr.
No
10-14, 20-27, 3539, 46, 49
28-34
3.7
100%
0
8 hr. per day
320 hr. per yr.
Yes
8.0
23%
6.0
10+
45%
5.0
150-300 hr.
per yr.
40 days per yr.
No
Day ahead
01-09, 11-19, 2027, 35-39
53-57, 59, 63-74
No daily
restriction
8 hr. per day
1-2
25%
0.5-1.5
8 hr. per day
40 days per yr.
Yes
Utility controlled
(instantaneous)
10, 13, 14, 28-30,
36, 37,
5+
Customer
Controlled
(one hour
notification)
45, 46, 48, 49, 67,
70, 80, 92, 97
1+
1 hour – 1 day
10 minutes
Day ahead
Table 7: Commercial/Industrial Non-Firm Rates Modeling Assumptions
Page 25
No
10. Additional Literature on Environmental and Regulatory Aspects of Stand-by
and On-site Generation
One specific consideration on interest in this study was the non-technical constraints to
customer-owned generation as an element in dispatchable load management programs.
We were able to locate and review three recent EPRI reports on this subject. The report
titles reviewed were:



“Distributed Generation Implementation Guidelines: Siting, Environmental
Permitting, and Licensing”, EPRI TR-111545, Final Report, December 1998. John
O’Sullivan, Project Manager.
“Environmental Performance, Regulation, and Permitting of Distributed Resources:,
EPRI TR-114183, Final Report, February 2000. Doug Herman, Project Manager.
“Assessment of Emission Control Technologies for Distributed Resource Options”,
EPRI TR-113743, Final Report, December 1999. Co-sponsored by EPRI and GRI. W.
Liss and J. O’Sullivan, Project Managers.
The first limitation in drawing conclusions from this literature is the 1000-fold variation
in the generation units considered – from 25 kW to 25 MW. Another limitation is the
variability across jurisdictions in terms of regulation and permitting requirements. The
three references above provide as complete a treatment as possible, and emphasize the
“problem areas” and “problem jurisdictions”. All three sources are very current. Each
also significantly duplicates the content of the other. The content of these three sources is
abstracted below.
As a general conclusion it may be said that DG installations smaller than 15-25 MW have
generally escaped onerous and complex emissions regulation – so far. However,
jurisdictions with are non-attainment for photochemical smog are much more strict than
other areas. All DG units no matter than size – except for a very few special exemptions –
must be permitted. However, the permitting process is well established and unless there
are special problems with the siting or technology usually do not present a barrier.
All these generalizations are subject to rapid change as the penetration of DG units
accelerates over the next few years.
10.1.
Environmental Emissions Considerations
The key emissions of concern are SO2, NOx, CO, hydrocarbons, and CO2. For the types
of distributed generation most commonly encountered – reciprocating engines and
turbines – the most important emissions from an air quality standpoint are NOx.
However, one potential “sleeper”problem is air toxics such as aldehydes, which may
require as-yet-undeveloped control technologies.
Generally speaking, NOx control in gas turbines is much easier than in reciprocating
engines. Current control technology for turbines can achieve 30-PPM NOx or less, while
the equivalent rate (on a lb.-mass NOx per MWH basis) for gas engines is five to ten
times higher.
Page 26
As NOx is a photochemical smog precursor, it is the most likely to be stringently
regulated. The most stringent emissions regulations are those requiring “Best Available
Control Technology”, or BACT.
For most areas, gas turbines are being installed with no add-on controls or at most lowNOx combustion technology. Reciprocating engines incorporating lean-burn alone or
rich-burn with catalytic reduction can meet most state control technology requirements.
At present many states offer exemptions from emissions requirements for applications
including standby/emergency and peak shaving, where operation is limited to less than
500 hours per year. However, as DG becomes more ubiquitous, it is likely that there will
be more and finer scrutiny.
In particular, air quality control agencies in non-attainment areas are just beginning to
realize the significance of the below-25 MW power generation category. The key states
to watch are California and the Northeast states. So far, only New Hampshire has
promulgated regulations for units in this size category. A major practicality is the
requirement that any “major source” of NOx, which is defined as emitting more than 100
tons per year, must comply with New Source Performance Standards (NSPS). The NSPS
in non-attainment areas is based on BACT. Table 5-4 of TR-113743 presents calculations
of exactly what size of combustion or reciprocating engine would fall below this cut-off
point for any given emissions control technology. Generally speaking, a well-designed
turbine can be as large as 50 MW without exceeding this limit.
10.2.
Permitting and Licensing Requirements
Prior to construction and installation, and in some cases again prior to operation, of a DG
unit, certain federal, state and/or local agency permits may be required. The permitting
requirements vary widely according to jurisdiction, air quality attainment status, size and
application of the DG unit, type of fuel, and other considerations. Both air and water
quality permits may be required, in addition to other permits such as land-use, health,
site, and construction.
Licensing is traditionally required for large power plant stationary sources of air and
water emissions. Whether or not a DG unit must be licensed in addition to permitted
depends upon size and jurisdiction. Licensing is a long, complex, multi-topical review
process. It starts with submission of a Notice of Intent and usually includes detailed
Environmental Impact Reviews and public hearings. Fortunately, in most states the
“trigger level” for licensing requirements is 25 MW or higher. In Washington State the
trigger point is 250 MW!
TR-114183 contains a comprehensive discussion of permitting requirements and the
permitting process. In many cases an exemption to permitting can be obtained if the
application is for emergency use, of insignificant size, will have limited hours of use, or
falls into one of several exempt categories including military, R&D, and agricultural.
Page 27
In some cases an Environmental Impact Report (EIR) is required before and air operating
permit can be obtained. An EIR requires specific treatment of the following additional
environmental assessment issues:
 Noise ordinances
 Aesthetics
 Hazardous materials storage and disposal
 Land use and Zoning
11. Additional Notes on the Literature Review Process
In addition to a traditional literature search, we also used the EnergySearch and
EPRISearch features on EPRIWEB and looked at several other relevant energy-related
web pages.
The other source of information and follow-up is from load management hardware and
software vendors and consultants. Most of this information was obtained through phone
interviews.
There are many other vendors of primarily communications equipment - CellNet and
Honeywell and Metricom and Itron and Scientific-Atlanta and many others. However,
this is not where the leading edge work is going on. System integrators such as Comverge
and Cannon Technologies and the software developers such as Silicon Energy are leading
the way.
In sum, there has been very little technology development from the late 1980's/early
1990's up to very recently, other than the constant improvement in the wireless
communications component of dispatchable load control.
However, the last year or so has seen the beginning of what could be a renaissance of
technology development and applications in the DLM field.
We provide below some additional details on the Descriptive Strings used in searching
EPRISearch and EnergySearch as well as the additional web pages we examined:


Descriptive Strings:
 Load Curtailment
 Dispatchable Load Control
 Load Control
 Load Management
 Appliance Load Control
 Residential Load Control
 Interruptible Rates
Additional web pages examined:
 www.optimumenergy.com
 www.panenergy.com
Page 28








www.eesconsulting.com
www.aesp.com
www.bpa.gov
www.energyonline.com
www.eia.doe.gov
www.esource.com
www.siliconenergy.com
www.cinergy.com
12. Templates for Candidate DLM Measures
As part of this project EPRI was asked to prepare a series of descriptive templates on
each of the potential dispatchable load management measures that BPA had under
consideration. Table 8 below summarizes the contents of this Appendix, which consists
of a series of templates containing summary quantitative and qualitative information
about each candidate DLM measure.
Page 29
DLM Candidate Measure Why is this Measure Promising?
Residential Sector
Residential Electric Water 1. Proven DLM technology in the
Heater Direct Load Control
NW
(REWH DLC)
2. Large market potential
3. Simple, inexpensive, customer
friendly
4. Available summer & winter
Residential Interactive
1. Convergence of energy services &
Thermostat Set Point
the inter-net
Control
2. Equipment becoming available
3. Large market potential
4. Available summer (cooling) &
winter (space heating)
Residential Dual-Fuel (LP 1. Proven DLM technology in upper
gas) Space Heating
Midwest
2. Available winter only
Residential Storage
1. Demand control plus off-peak sales
Heating
benefits
2. Available winter only
Nonresidential
Irrigation Pump Load
1. Proven DLM technology
Control
3. Large market potential
4. Mainly summer only
Commercial & Industrial
1. Proven DLM technology
Curtailable Rate
2. Large market potential
W/ Daily Load Curve
3. Very flexible
Benchmark
4. Competitive advantages
5. Available summer & winter
Standby Generator
1. Proven DLM technology
Program w/ sell-back spot
2. Competitive advantages
pricing
3. Available summer & winter
Commercial Buildings
1. Potentially large market
RTP w/ EMS
2. Competitive advantages
Who is Using it?












SCL & SPUD
Duke Power
Northern States
Pwr
Many others
Puget Sound
Energy
City of Austin
Others TBD
Northern States
Pwr
Many others
Great River
Energy
Some others

Northern States
Pwr
Many others
Cinergy
Northern States
Power
Others TBD


Duke Power
Florida Power



 Con Edison
 Gulf Power
 Georgia Power
Table 8: Candidate DLM Measures for BPA Consideration
Page 30
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Residential Interactive Thermostat Set Point Control Program
Applicable Residential Space Cooling and Space Heating
End-use or
Appliance:
Nature & Description Puget Sound Energy (PSE) is conducting a pilot project using Carrier, Silicon
Energy and CellNet called the Home Comfort Thermostat Program. The pilot
of DLM Option:
project is ongoing through April 26, with a White Paper to be published on
approach and results sometime in May or June 2000. This is a six-week trial
involving both an experimental group and a control group of homes with similar
R-value, building construction, and space conditioning systems.
The purpose of the pilot project is to determine whether this technology, along
with pricing innovations such as TOD rates and Real-Time Pricing, can facilitate
a win-win partnership with residential customers.
The PSE project involves 100 residential customers who have given PSE
permission to remotely adjust their thermostats, thus reducing energy usage.
Unless over-ridden by customers, the utility can adjust the set point by up to six
degrees for a period of up to four hours. Electric water heater operation can also
be disabled to increase overall demand reduction. The actual temperature of the
house is transmitted back to the utility and posted on a web site that the customer
can access. Customers can access the web site, check the indoor temperature,
and remotely adjust the set point – including over-riding the utility’s control if
they wish.
So far the pilot is going very well. The technology is working as advertised.
Early results indicate that customers are not only enthusiastic about the program
concept, but almost all (90%) of the participants are unlikely to over-ride utility
control when it takes place.
Carrier has developed a model, which can estimate the diversified demand
impact given temperature conditions and type and degree of thermostatic setpoint control. This model will be compared against actual results from the pilot.
In the PSE pilot the communications is done with CellNet’s wireless system;
however, any two-way communications will suffice.
Customer Class or Segment:
Customer Population
(000s):
Residential
TBD
Page 31
Demand and Energy
Characteristics:
End-use load shapes for residential air conditioning and
electric space heating vary widely depending on season,
region, house size, type, and age, and heating and cooling
system type, size and age.
PSE is assuming that the average diversified coincident peak
demand of residential summertime air conditioning is about
3.0 kW. Previous research at Seattle City Light indicates an
average diversified coincident peak demand for wintertime
electric space heating of about 4.0 kW.
Estimated Mean-per-Unit (MPU) Maximum Diversified Thermostatic set point adjustment of
Demand (kW) & basis (shed, cycle, or defer*):
six degrees constitutes a cycling
strategy. A 50% cycle strategy will
generate load reductions between onequarter and one-third of the diversified
demand (depending on temperature
severity; similar results were obtained
by PG&E and others). Assume a
reduction of 25% of maximum
diversified demand for both space
heating and space cooling to yield:
Air conditioning: 0.75 kW
Space heating: 1.0 kW
Coincidence Factor for BPA Winter Peak
Demand:
Air conditioning: 0.0
Space heating: 0.9
Coincidence Factor for California or other
Summer Peak Demand:
Air conditioning: 0.9
Space heating: 0.0
Estimated MPU monthly energy
use (kWh):
Estimated Energy Impacts
Per Operation (kWh) & basis:
Summer Winter
459*
0
0
1455*
2.4**
0
0
3.2**
Air Conditioning
Space Heating
Air Conditioning
Space Heating
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
There will be some lag between dispatch and load relief due to the
thermal lag of the thermostat control system and the residential thermal
mass. This could be as long as one hour or more.
Availability:
Winter seasonal availability for space heating is good.
Summer seasonal availability for space cooling also good.
Spring and Fall availability may be marginal.
Persistence:
Unknown.
Page 32
Weather sensitivity:
Both summer air conditioning and winter heating are weather-driven
end-uses and thus are sensitive to temperature extremes. Demand
availability will generally increase with temperature severity, as the
natural duty cycle will be longer in order for the appliance to keep up
with the thermal demand.
Net Energy Impact:
Modest. If usage is deferred to a later period then the need for cooling or
heating may not be as great due to smaller delta-T between the inside
and outside environment.
Measurement &
Verification:
As these are two-way devices with interaction via a web page, M&V
capabilities are included.
Scaleability:
Would expect some reductions in system-level demand impacts due to
diversity.
Measure Costs:
Equipment Costs:
End-use
$400 per house
Control
Communica
Included above
tions
Billing &
Extra
Metering
Customer Incentive costs:
$25 per month
Other program & admin. costs:
TBD
References /Footnotes:
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to
defer demand to a later period
*Monthly MPU estimates for space heating are based on actual Seattle City Light results. See
reference below. Monthly MPU estimates for space cooling calculated assuming 20% duty cycle.
**Energy impacts (lost sales) estimated assuming 20% of foregone usage would not be replaced
by deferred usage.
References:
1. “1984-1985 Progress Report to the California Energy Commission”, PG&E Summertime
Break Program, Rate Department, Load Management Section, November 1985
2. EPRI TR-103993, T&D Benefits of Direct Load Control: Seattle City Light and
Snohomish PUD Pilot Project Evaluations (November 1993)
3. EPRI EM-3861, Residential Load Management Technology Review (February 1985).
Section 7, “Water Heater Load Management”.
4. EPRI EM-3882, Control Strategies for Load Management (July 1985). Section 3: Overview
of Load Control Techniques and Strategies.
5. Interviews with Jerry Thomas of Puget Sound Energy & Allan Schurr of Silicon Energy
Page 33
Template for Evaluating Dispatchable Load Management (DLM) Measures
Measure
Name:
Residential Electric Water Heater (EWH) Load Control
Applicable Residential electric water heaters – double element, 40 or 80 gal capacity
End-use or
Appliance:
Nature &
Domestic electric water heating load control is very common throughout
Description of DLM the US. Detroit Edison pioneered this load control application, with 200
Option:
MW under control in the early 1980’s. Currently many utilities still
maintain EWH DLM programs, notably Florida Power Corp, Duke, and
Northern States Power.
This DLM measure description is based on the residential direct loadcontrol measures used by Seattle City Light and Snohomish PUD in the
early 1990’s. The purpose of the program was system and local network
peak load reduction. SCL called their program the City Light Peak Energy
Program; SPUD called theirs the Water Heater Peak Savers Program.
Both programs involved installation of switches on the water heaters
which were activated by one-way radio or power line communications.
Load control was exercised on a 2-3 hour “shed” strategy or “50% cycle”
strategy between the hours of 7 am and noon on winter mornings.
Control was exercised up to 20 times per winter and customers were paid
as much as $75 for participating.
In the particular pilot program reported on in EPRI TR-103993, high
levels of program saturation were sought on several overloaded feeder
circuits. The project demonstrated the capability to deliver both system
and local network load relief.
Customers were overwhelmingly satisfied with the program and in fact
over 80% “did not notice” the load control effects.
The program yielded load impacts of up to .9 kW with little or no energy
penalty.
Customer Class or Segment:
Residential
Customer
Population (000s):
TBD
Demand and Energy
Characteristics:
Estimated Mean-per-Unit (MPU) Maximum
SCL: 0.9 kW ± 0.1 kW maximum
Diversified Demand (kW) & basis (shed, cycle, or diversified demand in the 8 am weekday
defer*):
hour for 2 or 3 hour shed.
SPUD: 1.15 kW ± 0.1 kW maximum
diversified demand in the 8 am weekday
hour for 2 or 3 hour shed.
Page 34
Because the natural diversity of the water
heater load has been altered by utility
control, the problem of demand “payback” (similar to cold-load pick-up) must
be addressed. Without any mitigating
strategy, a demand pay-back of 1.5 – 2.5
kW for one-two hours after shed control is
relinquished can be expected. Mitigation
strategies include dividing the controlled
customers into groups and relinquishing
control over a few groups at a time. This
is called “ramping-out” of the control and
can reduce the pay-back spike by onethird or more.
Coincidence Factor for BPA Winter Peak
Demand:
0.9
Coincidence Factor for California or other
Summer Peak Demand:
Unknown
Summer Winter
(avg.
Dec.Mar)
Estimated MPU monthly energy Unknown 320.
use (kWh):
Estimated Energy Impacts
Per Operation (kWh) & basis:
Less than 1.0 kWh per 3 hour shed
operation (negligible)
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
Load impact is virtually instantaneous, similar to a hydro resource.
Availability:
Very high during the winter months, although per-unit load impact varies
throughout the day.
Persistence:
Unknown.
Weather sensitivity:
Actual data from ‘92-’93 in Seattle indicate per-unit load impact
increases as minimum temperature decreases. Relationship with
summer high temperatures unknown.
Net Energy Impact:
Negligible. See above.
Measurement &
Verification:
Switch operation in “shed” mode easy to verify with lighting logger type
setup or the counter function built into most load control switches.
Scaleability:
No diversity impacts between individual house and feeder circuit level.
Page 35
Measure Costs:
Equipment Costs:
End-use Control
$75 per point
Communications
$75 per point
Billing & Metering
May be negligible.
Customer Incentive costs:
$75 per winter per customer
Other program & administrative costs:
25% of total of other costs
Total Estimated
Costs
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to
defer demand to a later period
References:
1. EPRI TR-103993, T&D Benefits of Direct Load Control: Seattle City Light and
Snohomish PUD Pilot Project Evaluations (November 1993)
2. “Ten Years of Operating Experience with a Remote Controlled Water Heater Load
Management System at Detroit Edison”, B. F. Hasting, 1979 IEEE Transactions F 79 648-7.
3. EPRI EM-3861, Residential Load Management Technology Review (February 1985).
Section 7, “Water Heater Load Management”.
4. EPRI EM-3882, Control Strategies for Load Management (July 1985). Section 3:
Overview of Load Control Techniques and Strategies.
5. Interviews with Joel Cannon of Cannon Technologies
Page 36
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Residential Thermal Storage (w/ ceramic bricks)
Residential Dual-Fuel (w/ diesel or LP)
Applicable Residential Space Heating
End-use or
Appliance:
Nature & Description Both residential thermal storage and residential dual-fuel programs date
of DLM Option:
to the mid-80s and may be found almost exclusively in the Upper
Midwest and Great Plains areas. These are all regions where there is no
pipeline gas available and all-electric homes are common. They are also
regions where it is very cold in winter and winter-driven peaks are big
problems for distributors and G&T utilities.
Leading utilities in both these areas include Minnkota Power, Northern
States Power, and Great River Energy. We will focus on Minnkota
Power’s programs as our example.
Minnkota Power Cooperative, with headquarters in Grand Forks, North
Dakota, has had both a residential thermal storage heater and a
residential dual fuel program for many years. The programs serves
double-duty in that it builds off-peak load, improving annual load factor,
and provides on-peak demand reduction. The Minnkota program includes
30 MW (diversified maximum demand; nameplate capacity/noncoincident
peak is 90 MW) of controllable dual fuel heating load and another 10 MW
(diversified maximum demand; nameplate capacity/noncoincident peak is
30 MW) of controllable thermal storage space heating.
The thermal storage units consist of two types: (1) ceramic brick heating
units that come in individual room sizes or large central whole-house
sizes; and (2) slab storage heating.
The individual ceramic brick room units would be fairly small – 2.5 ‘ tall, 3
‘ wide, and 1 ‘ deep – and would be bolted to the wall. The ceramic bricks
contain electric coils taking 220 V service. The inside temperature can
reach 500 to 600 degrees F. The bricks are heavily insulated and
contained in a unit providing radiant heat transfer to the room. Fully
charged, the units can provide 1500 BTUH for an 8-10 hour period.
Installed cost is around $1000. A whole-house version would be much
larger and would be part of the forced-air circulation system. Cost would
be $6,000 installed. The ceramic brick thermal storage space heating
configuration is typically used for retrofit applications where the home is
already all-electric. There is only one US manufacturer of these systems
– Steffes Corporation. They have a good web page at www.steffes.com.
The slab storage heating is only economical on new construction.
Heating cables or hydronic pipes are buried under the house or, where
there is a basement, embedded in a heat-insulating gypsum floor board.
Again, the slab storage heating would be used in an all-electric home.
The thermal storage space-heating unit is separately metered or
Page 37
submetered. Minnkota exerts daily control over the units, turning them on
and off to avoid their double-humped (early morning and late evening)
peak. Twelve hours of electric charging is sufficient to provide an eighthour thermal charge. The customers receive a discount on their space
heating load and pay only 3.2 cents per kWh for this load.
More sophisticated control schemes for thermal storage space heating
involves an outside temperature sensor which measures the delta-T and
adjusts the percentage of maximum capacity that the bricks are charged
to. This refinement solves the problem of over-charging or undercharging the thermal mass, which can lead to thermal discomfort due to
either over-heating or under-heating of the living space.
Minnkota’s residential dual fuel space heating program is much larger
than the thermal storage program, with a total 220 MW maximum
diversified space heating demand under utility control. This program
dates back to the late 1970’s, when many homes with fuel oil or LP
heating systems were uneconomical or even impractical given fuel
shortages. It is relatively inexpensive (about $1200) to retrofit the plenum
of a forced-air heating system with a staged series of four electric coils of
2500 W each. A control box containing a latching relay is then installed
on the furnace, which allows the heating mode to be switched remotely
and positively (both on and off of electric) at the utility’s command.
Operation of the dual-fuel heating load-control program is reserved
for exceptional cases where there is under-capacity or when
wholesale purchase prices are very high. This is because of the
implicit energy sales penalty whenever customers switch from
electricity to fuel oil or LP gas. Minnkota can operate these
customers for up to 400 hours per year, with a control period of up
to 16 hours.
Both of these programs make economic sense only when combined with
a substantial energy discount from the utility. With the discount these
dual -fuel heating customers pay about 3 cents per kWh for their
electricity.
Minnkota uses a low-frequency PLC (Power Line Carrier)
communications system with injectors at 13 115 kV and 69 kV
substations located throughout their 16 distribution co-ops.
Customer Class or Segment:
Residential – Inland areas only
Customer Population
(000s):
TBD
Demand and Energy
Characteristics:
This program would best apply to customers with significant
heating loads – Eastern Washington, Oregon and Idaho.
These customers would likely have fairly flat electric heating
load curves with an early morning peak – a load shape not
dissimilar to coastal customers but with a higher maximum
diversified demand. The residential customers in the
Page 38
Minnkota program have a diversified maximum demand for
space heating of about 8-10 kW per home.
The thermal storage system is designed to charge up
overnight and then provide up to 8 hours of storage space
heating without any power requirements. The control strategy
used ensures the unit only operates during off-peak hours.
Estimated Mean-per-Unit (MPU) Maximum Diversified The control strategy is equivalent to a
Demand (kW) & basis (shed, cycle, or defer*):
shed of the entire maximum diversified
demand: 8 kW
Coincidence Factor for BPA Winter Peak
Demand:
Very high – 0.8 or 0.9
Coincidence Factor for California or other
Summer Peak Demand:
Not Applicable
Estimated MPU monthly energy
use (kWh) for space heating:
Estimated Energy Impacts
Per Operation (kWh) & basis:
Thermal Storage Space Heating:
Dual-Fuel Space Heating:
Summer Winter
N/A
2880**
N/A
N/A
Average annual space heating use for
Minnkota customer is 20,000 kWh!
Storage space heating will have a
negligible or even positive energy
0/positive‡ impact. Dual-fuel space heating has a
Large
very substantial energy impact
depending on how frequently it is
operated.
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
The thermal storage space-heating program looks exactly like a native
peaking power plant. It is dispatched every day during the peak period.
The dual-fuel space-heating program looks like a wholesale power
purchase.
Availability:
Availability is very good during the winter season, depending on
temperature severity. Minnkota’s heating season is November 1 through
May 1.
Persistence:
The ceramic brick technology may undergo some deterioration in storage
capacity but this is typically handled in the thermal sizing calculation. No
persistence problems likely with dual-fuel systems.
Weather sensitivity:
The control technology used for thermal storage space heating explicitly
factors in temperature severity. Higher delta-T’s result in more thermal
charging of the bricks in anticipation of higher thermal loading during the
next discharge period.
Similarly, during adverse weather conditions the dual-fuel system will
simply substitute for oil or LP gas for on-peak electricity demand.
Page 39
Net Energy Impact:
See above. Thermal storage programs often have a net energy increase
due to losses in storing and discharging the thermal energy. Dual fuel
heating systems have a major and adverse energy sales penalty and as
a result are operated as infrequently as possible – or only when
economic compared to wholesale power purchases.
Measurement &
Verification:
The time relay with one-way refresh by a central station guarantees
proper operation of the thermal storage systems. Improper operation
under a separate or sub-metering scheme would be detected via
monthly bills.
Scaleability:
Unknown.
Measure Costs:
Equipment Costs:
Customer purchases thermal brick system or electric
plenum coil inserts, perhaps with a utility-provided discount
or incentive
$500
End-use
Control
Communica
Included above
tions
Billing &
Nil
Metering
Customer Incentive costs:
Energy discounts for controlled space heaters
provide major incentive
Other program & administrative
Could be $25 per customer per year
costs:
Footnotes:
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to defer
demand to a later period
**MPU Monthly Energy Usage estimated as: 8 kW * 12 hours recharge per day*30 days per month
‡ Impact on sales of this or other storage technologies may be positive due to losses in storing and
releasing stored energy
References:
1. Phone conversation with Doug Baacker of Cannon Technology
2. Phone conversation with Roger Simmonson of Minnkota
3. Steffes Corporation Web Page (www.steffes.com)
4. “Special Report: Utilities Embrace Direct Load Control”, Electrical World, February 1982.
Page 40
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Agricultural/Irrigation Pumping Load Control
Applicable Agricultural/Irrigation pump load control programs, administered by both electric
End-use or distributors and G&T utilities, have been in place for many years. Most of the
Appliance: agricultural/irrigation pump load control is currently in the southwest and the upper
Midwest. Customers can be either individual farmers with single or multiple pumps in
the size range 25 to 50 Hp, or an irrigation district, which may operate dozens of
pumps as large as 500 Hp.
Nature & Description There are agricultural/irrigation pumps of every description - centrifugal,
of DLM Option:
reciprocal, submersible, tube-well, electric, gas, diesel, high head, low
head, high capacity, low capacity, and so on.
It is impossible to try and capture this diversity concisely, other than by
using a representative average case. This template assumes a program
similar to that in place at Great River Energy Co-Op for the past ten
years. Great River Energy is a publicly owned G&T serving 29 member
coops. It is Minnesota’s second-largest utility, with 1600 MW of capacity
and $400 million in annual revenues.
GRE’s irrigation pump control program totals 45 MW of peak demand
reduction. Individual growers participate by placing their pumps, each
with an average diversified demand of 35 kW (50 Hp pump), most of
which are 3-phase. GRE uses an FM/VHF one-way load control system.
The pump control is via the safety circuit; when the switch is remotely
operated it opens up the series circuit. The circuit then has to be
manually reset to resume operation.
The pumps irrigate fields where corn and potatoes are grown. Depending
on soil conditions the irrigation cycle is 20 hours on, then one or two days
off. The Irrigation pumping season starts in April and can extend through
August.
The tariffed operation rules include a frequency of control of up to 8 times
a summer and a set duration of four hours. The control period is always 4
PM to 8 PM, so growers know they can get out to the fields before
nightfall in order to manually restart the pumps. There is no ramp-in or
ramp-out strategy, and the pump can usually recoup the irrigation
requirements by running overnight.
Customer Class or Segment:
Agricultural sector
Customer Population
(000s):
TBD
Demand and Energy
Characteristics:
Agricultural and irrigation pumps are seasonal loads, usually
peaking in the mid-to-late summer, when water requirements
are higher and rainfall is low. Pumps operate most efficiently
when they are fully loaded and operated on a continuous
Page 41
basis. In fact, the daily load shape of particular pump can
vary widely depending on many factors including: sizing of
the pump capacity relative to the volume of water to be lifted,
type of crops irrigated, existence of pondage or other storage
capacity, and the schedule of upstream irrigation water
deliveries. This template assumes flat daily load shapes for
agricultural pumping during the growing season.
.
Estimated Mean-per-Unit (MPU) Maximum Diversified
Demand (kW) & basis (shed, cycle, or defer*):
For a shed strategy, 35 kW
Coincidence Factor for BPA Winter Peak
Demand:
Nil…these are summer-only loads
Coincidence Factor for California or other
Summer Peak Demand:
High… 0.8 or more
Estimated MPU monthly energy
use (kWh):
Estimated Energy Impacts
Per Operation (kWh) & basis:
Summer Winter
13,000
N/A
130
(Assume
1%)
N/A
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
This is a very desirable program from a dispatchability viewpoint. Load
reduction is almost instantaneous once the signals have been sent.
Availability:
Need to distinguish between seasonal availability. Summer seasonal
availability is pretty high, on the order of 0.6. Not available in winter.
Persistence:
Negligible derating. Pumps last 8-10 years with minimal load changes.
The demand reduction available may decrease slightly with the age of the
pump.
Weather sensitivity:
There is a positive correlation between hot weather and the need for
more irrigation.
Net Energy Impact:
Negligible, as the pump must still operate enough to fulfill the irrigation
volumetric requirements.
Measurement &
Verification:
Most load control devices have a counter function that keeps track of
how many times the switch operated. The counter can be inspected
periodically and compared against the # of operations signaled over the
period. In instances where a farmer has multiple pumps serving the
same field, some pumps may not be operating when load control is
initiated – obviating the demand reduction expectation for such pumps.
Page 42
Scaleability:
Unknown.
Measure Costs:
Equipment Costs:
End-use
Control
Communicatio
ns
Billing &
Metering
Customer Incentive costs:
Other program & administrative costs:
$200 per point, or
$6.00 per kW
Included in end-use control device cost
Negligible
Up to $50 per kW per season
$50 per pump per season
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to
defer demand to a later period
References:
1. Phone conversation with Roger Rognli of Great River Energy
2. Phone conversation with Doug Backer and Joel Cannon of Cannon Technologies
3. Phone conversation with Larry Liss, Nebraska Public Power District
4. Phone conversation with Roger Simmonson, Minnkota
5. Phone conversation with LaVerne E. Stetson, University of Nebraska (retired)
6. Phone conversation with Dale Heermann, USDA, Colorado State University
7. Phone conversation with Fred Zaire, Irz Irrigation Consulting, Hermiston, Oregon
8. NRECA Short Note Report: Irrigation Load Management Options and Opportunities
Page 43
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Commercial & Industrial Curtailable Rate w/ Daily Load Profiling &
Buy-Back (“Demand Exchange”)
Applicable Nonresidential customers over 100 kW
End-use or
Appliance:
Nature & Description There are at several variations of this DLM measure in place. We will use as our
example an amalgam of Cinergy’s “PowerShare” program and Apogee
of DLM Option:
Interactive’s “Demand Exchange” program as implemented by the CowetaFayette EMC.
In 1998 and 1999 Cowetta-Fayette faced wholesale purchase prices over $4,000
per MWh on some days. In response, and working with Apogee, they introduced
an Internet-based auction where customers could first view a day-ahead price
forecast and then signal their interest in reducing demand in certain hours for the
specified price. After verification, the customers would receive a credit on their
bill or a separate check. Signal (day-ahead) prices on a very high-wholesaleprice day could reach $1.75 per kWh, with actual settlement prices topping $3.00
per kWh. The customer is paid according to the signal price, and the utility saves
the difference between the settlement price and the signal price.
The Cinergy PowerShare program is based on an agreement, “CallOption”,
between the utility and the customer. In the CallOption agreement the customer
identifies a Strike Price. When the day ahead forecast of Cinergy’s production or
wholesale purchase cost includes prices above the Strike Price, they can exercise
the CallOption and the customer must reduce their usage by the agreed-upon
levels during the afternoon hours of the following day. The Strike Prices vary
from $0.10 per kWh to $0.90 per kWh.
The customer receives both a guaranteed monthly Premium on their summermonth bills and an additional credit every time the customer is called upon to
curtail their demand. There are numerous options within the overall CallOption
program structure that a customer can choose from. The Monthly Premium is
highest for the lowest “strike price” and combinations of curtailment duration
and frequency that are more severe. Customers can choose between eight hours
and four hours duration and a frequency between four and twelve curtailments
per summer. The energy credit, which applies to each individual curtailment, is
the product of contracted curtailment amount * hours of curtailment* strike
price.
There is also a Shared Energy option within the CallOption program structure. In
this option the Monthly Premium is only half the regular amount, but the energy
credit is much higher because it is based on the spot market price that Cinergy
faces. Under this option the customer can receive up to 50% of the actual savings
the utility achieves when they call for that customer to curtail their load.
There are also several variations in the basis of the agreed-upon level of demand
reduction. The CallOption Firm Level Plan is familiar: it requires the customer
to reduce load to below a specific target level (often called a Firm Service
Level). Another plan, the CallOption Baseline Reduction Plan, allows the
Page 44
customer to reduce their load by a fixed amount of their usual consumption.
Other schemes include CallOption End Use Plan, where the customer identifies a
certain process or piece of equipment to be shut down, and the CallOption Power
Generation Plan, where you agree to self-generate a portion of your load upon
request.
The latest program Cinergy offers is called QuoteOption. It is new this year.
Cinergy will post a price quote and time schedule for load reduction on their
internet site at 8 in the morning. The participating customers can go to the web
site and indicate how much load relief they can provide at that price quote. By 9
am customers must commit to providing a certain level of load relief on a certain
schedule. If they do commit then Cinergy provides a pro forma load shape for
that customer to access. The load shape for the eight-hour period that Cinergy
provides becomes the benchmark for what the customer can do and how they
will be compensated for their performance. The QuoteOption program is
designed to be risk-free to the participant. If the customer’s load is above the pro
forma load shape benchmark, there is no penalty; if it is below the load curve the
customer is compensated based on the price quote provided.
All of these programs presume a very detailed knowledge of the operating
characteristics of participating customers. In particular, it is crucial to have an
ongoing capability or method of load profiling each participant so that a forecast
or normal load shape can be compared with the actual load shape achieved when
a curtailment is called upon. Cinergy has a program that estimates for each
customer what they think the normal load curve would be, given the forecast
temperature and customer billing history, day of the week, etc. Customer
compliance, as well as calculation of energy credits, are based upon the
comparison between this estimate and the actual loads achieved on a given
curtailment day.
Customer Class or Segment:
Commercial, Industrial, Agricultural, General Service
Customer Population
(000s):
TBD
Demand and Energy
Characteristics:
These programs are individualized to each customer’s load
shape and ability to curtail demand on a given day and for a
given incentive. Cowetta-Fayette has six large customers
participating representing 3 MW of controllable load. Cinergy
is actively marketing both programs to their mid-sized and
larger C&I customers. The target is to attract up to 500
customers around 1 MW and greater and sign up as much as
250 MW on the program over the next two years.
Estimated Mean-per-Unit (MPU) Maximum Diversified The diversified demand reduction
Demand (kW) & basis (shed, cycle, or defer*):
achieved will vary depending upon
customer type, program option
selected, prices on a particular day,
and many, many other variables.
Coincidence Factor for BPA Winter Peak
Demand:
Coincidence with an 8 am weekday
peak for commercial/industrial
customers generally will be fairly high:
perhaps 0.8. Note that both the
Page 45
programs cited are summer-oriented
programs.
Coincidence Factor for California or other
Summer Peak Demand:
Estimated MPU monthly energy
use (kWh):
Coincidence with a 4 PM weekday
summer peak will be very high – 0.9
Summer Winter
TBD
TBD
Estimated Energy Impacts
Per Operation (kWh) & basis:
There will be lost energy sales as a
result of curtailments; however, they
will for the most part be restricted to
hours where the utility is losing margin
anyway.
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
Because most of these programs involve customer actions predicated on
day-ahead forecasts, they will look to the dispatcher like scheduled
generation coming on line. Although not dispatchable, they will look like
generation.
Availability:
Commercial/industrial load availability is generally very high on a yearround basis. Note however that the frequency and duration of operations
are both highly restricted – a maximum of 96 hours in the case of
Cinergy.
Persistence:
Previous curtailment programs have shown that performance in terms of
load reduction actually improves over time as customers become more
proficient in achieving demand reductions.
Weather sensitivity:
This will depend upon the load mix of particular customers. Weathersensitive loads will increase, but the ability of customers to curtail
heating or cooling loads during adverse weather may be less.
Net Energy Impact:
There is a negative energy impact from curtailable programs. Some
industrial customers may just postpone usage from one period to
another, but commercial customers will simply go without. Note,
however, the net impact on margin or utility profitability will be likely be
positive as curtailments are only scheduled when generation is
unavailable or expensive to run or high-priced power purchases are
necessary.
Measurement &
Verification:
This is an absolutely key issue for curtailable programs. The issue is not
so much measuring the actual loads during a curtailment, as all these
customers will have interval meters. The difficult issue is load profiling
on comparable non-curtailment days so there is a good benchmark
against which to judge actual measured performance.
Scaleability:
Unknown.
Page 46
Measure Costs:
Equipment Costs:
End-use
Control
Communica
tions
Billing &
Metering
Customer Incentive costs:
Other program & administrative
costs:
None
Account rep will actually give a courtesy call on days when a
high-cost day ahead forecast is forthcoming.
Customer responsible for incremental metering. Hourly
interval metering, including daily uploads to a central MV-90
system, already in place.
Customer gets monthly premium and energy
credits as described above.
Cinergy budget is only $100,000. It builds on the RTP
infrastructure already in place. LoadMap system uses the
incoming data from MV-90 to constantly improve/revise
each customer’s benchmark load curve.
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to defer
demand to a later period
References:
1. “Capitalizing on the Peak Load Management Opportunity”, Workshop Proceedings, Oct. 14-15,
1999. Sponsored by NYMEX, EPRIP, EEI, NRECA, AESP, and The Demand Exchange.
2. “Cinergy PowerShare Program Brochure”, provided by Harry Darnell of Cinergy.
3. Phone Conversations with Harry Darnell of Cinergy
Page 47
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Standby Generator Program w/ sell back based on spot prices
Applicable Buildings and industrial facilities
End-use or
Appliance:
Nature & Description Many utilities have special offerings for customers with standby,
of DLM Option:
emergency, or auxiliary self-generation available. A 1991 EPRI study
(CU-7316, “Customer Back-up Generation: Demand-Side Management
Benefits for Utilities and Customers”) identified 18 large utility programs,
including some with 100 MW or more of standby generation available.
These programs have been in place for many years and vary
considerably in design. Two recent innovations as exemplified by Cinergy
and Duke.
In the case of Cinergy, customers with self-generation can join the
CallOption Power Generation Plan. In this plan the customer chooses a
“Strike Price” which determines when the utility requests for them to selfgenerate, thus reducing the load and energy to be served by the utility.
By choosing a low strike price and taking the shared energy plan, the
customer-owned generation could be operated up to 96 hours per year.
Duke Power also has a recently revamped standby generator program.
This works via an alert relay tied to the generator, which spools up the
generator in advance of curtailment notification. This is a pay-forperformance scheme, where the customer is actually paid for the kWh
they generate. This is a very popular program, as Duke will come in to
test and maintain their generator program and provide reports to
management and regulators that the customer would otherwise have to
provide. Duke believes this is also a very promising program that could
be significantly expanded. At present about 60 MW of the total 800 MW
of interruptible/curtailable load is on the standby generator program.
Customer Class or Segment:
Commercial and Industrial Customers
Customer Population
(000s):
TBD
Demand and Energy
Characteristics:
Estimated Mean-per-Unit (MPU) Maximum Diversified Generators come in all sizes, but a
Demand (kW) & basis (shed, cycle, or defer*):
common configuration is 500 kW-2,000
kW. The latest thing is microturbines,
some of which are even configures for
cogeneration.
Page 48
Coincidence Factor for BPA Winter Peak
Demand:
Commercial/Industrial load should be
fairly coincident – say, 0.8.
Coincidence Factor for California or other
Summer Peak Demand:
Commercial/Industrial load should be
very coincident – use 0.9.
Estimated MPU monthly energy
use (kWh):
Estimated Energy Impacts
Per Operation (kWh) & basis:
Summer Winter
TBD
TBD
TBD
TBD
Depends on the amount of load,
duration of curtailment, and amount of
energy that is deferred or rescheduled
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
These programs are imminently dispatchable. Duke’s program essentially
treats the customer-owned generation as a remotely controlled
generation resource.
Availability:
These generators are available year-round, as is the
commercial/industrial load they serve.
Persistence:
Only some nominal derating over the lifetime of the generating unit.
Weather sensitivity:
The generator capacity available is not weather sensitive; the amount of
customer load it satisfies can be.
Net Energy Impact:
Sales are lost when the customer self generates. Therefore, the utility
should only dispatch this generation when it is more expensive for the
utility to serve the load than it is for the customer to self-generate.
Measurement &
Verification:
Both the customer load and the generator output need to be intervalmetered.
Scaleability:
No diversity effects with generation.
Measure Costs:
Equipment Costs:
End-use
Cost of Relay: $500
Control
Communica
Cost of comm. line: $500
tions
Billing &
All customers already on interval metering. Additional cost of
Metering
metering generation paid for by customer.
Customer Incentive costs:
Customers save by both a premium to interrupt
or curtail load and an energy credit for the
amount they self-generate.
Other program & administrative
$200 per customer per year
costs:
Page 49
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to defer
demand to a later period
References:
1. “Customer Back-up Generation: Demand-Side Management Benefits for Utilities and
Customers”, EPRI CU-7316, July 1991.
Page 50
Template for Evaluating Dispatchable Load
Management (DLM) Measures
Measure
Name:
Commercial/Industrial Real-Time Pricing
Applicable Commercial and Industrial Customers larger than 250 kW
End-use or
Appliance:
Nature & Description Real-time pricing based on Southern Company’s system Lambda. Two
of DLM Option:
options: Hour ahead and day ahead. Larger industrials are typically on
the hour-ahead, which has more volatility, while the smaller commercial
customers are on the day-ahead option. Georgia Power’s program
involves 1500 customers representing 5,000 MW of contract load and
about 4,000 of maximum diversified demand.
Price variability is quite high, with historical variations between 3 cents
per kWh to as much as $1.00 per kWh. Maximum load response was 750
MW on a very hot, high demand day when Southern Company was
purchasing very expensive resources from the wholesale market.
Big issue is accuracy of forecasting – can the day-ahead forecast
accurately predict the effects of forced outages and extreme weather?
Price elasticity’s of demand are around 0.1. This is fairly inelastic. Some
customers – especially large industrial customers in certain SIC codes
(28, 32, 33) – have elasticities as high as 0.25. Particularly promising
customers include assembly industries and primary metals, water
treatment and water supply and pipelines.
Customer Class or Segment:
Commercial and Industrial
Customer Population
(000s):
Over 250 kW commercial and residential customers
Demand and Energy
Characteristics
Customers on this rate have both high and low load factors.
The hour-ahead customers typically have very flat loads. The
smaller customers are typically commercial customers with
commercial load shapes.
However, the price elasticity of demand – and % demand
reduction – is pretty similar across smaller and larger
customers.
Estimated Mean-per-Unit (MPU) Maximum Diversified Assume 10-15% reduction in normal
Demand (kW) & basis (shed, cycle, or defer*):
loads for price spikes 4-5 times the
average and up to 20% reduction for
spikes up to 10 times the average.
Coincidence Factor for BPA Winter Peak
Demand:
TBD
Page 51
Coincidence Factor for California or other
Summer Peak Demand:
Estimated MPU monthly energy
use (kWh):
Southern Company peak is about 4
PM. Peak price time is about 5 PM.
Summer Winter
Variable Variable
Estimated Energy Impacts
Per Operation (kWh) & basis:
Not Applicable
Discussion of Key Measure
Design Considerations,
Characteristics & Risks:
Dispatchability:
This program does not involve positive control of loads and thus is
subject to the risks and lags of market response. Also since it is an hourahead program then it takes at least one hour and more like two hours for
the demand reduction to register.
Availability:
The program is always available; however, rating/forecasting the
expected load reduction for a particular time and price is the key factor.
Persistence:
No drop off has been seen so far. In theory the long-run price elasticity
would be larger than the short-run elasticity as customers make
investments and modify their operations to accommodate RTP pricing.
Weather sensitivity:
The industrial load will not change too much with weather. On a very hot
day the reference load for the entire group would be higher. Since the
response comes from that, there is potentially more load reduction
available. However, since hot weather correlates with high prices,
response could possibly be larger.
Net Energy Impact:
The two-part design is developed to be revenue neutral. The original
impetus of the program was to pass along prices more reflective of
marginal costs to industrial customers. Industrial sales for Georgia
Power have grown as a result of this program.
Measurement &
Verification:
All customers have hourly interval meters.
Scaleability:
Unknown.
Measure Costs:
Equipment Costs:
End-use
$1000 per customer for all required communications and
Control
signaling equipment.
Communica
Included above.
tions
Billing &
Nil. Customers have interval meters already.
Metering
Customer Incentive costs:
None. Customers are attracted by lower energy
Page 52
Other program & administrative
costs:
prices
Low. Perhaps $100 per customer per year.
*Shed: 100% of the end-use load is interrupted for a set or
preset period of time
*Cycle: The natural duty cycle of the end-use is manipulated to lower it to some target level, such
as 33% or 50%
*Defer: The operation of the end-use is manipulated via a thermostat or other control so as to defer
demand to a later period
References:
1. Phone conversation with Steve Braithwaite of Christensen Associates
Page 53