DR NPCC - Assessing-Dr-Potential-For-Seventh-Power-Plan - Updated-Report - 1-19-15
DR NPCC - Assessing-Dr-Potential-For-Seventh-Power-Plan - Updated-Report - 1-19-15
DR NPCC - Assessing-Dr-Potential-For-Seventh-Power-Plan - Updated-Report - 1-19-15
Prepared for:
Northwest Power and Conservation Council
415-399-2109
www.navigant.com
1. Summary .................................................................................................................................. 1
1.1 Introduction .............................................................................................................................................. 1
1.2 Approach .................................................................................................................................................. 1
1.3 Overall Results ......................................................................................................................................... 3
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1. Summary1
1.1 Introduction
The Northwest Power and Conservation Council (NPCC) commissioned Navigant to conduct a
preliminary assessment of Demand Response (DR) programs and potential that could ultimately form
the basis for DR-related inputs to the upcoming Seventh Power Plan. This report outlines the process by
which Navigant went about developing representative DR programs that could be considered,
identifying the parameters that would be associated with the applicable DR programs, and identifying
the market potential and cost associated with the DR programs. While the Western Electricity
Coordinating Council (WECC) has developed estimates of DR potential that are representative for the
entire WECC region, NPCC wanted this effort to be more tailored to the unique conditions that are
present in the Northwest, which may not have been ideally captured from the broader WECC study.
1.2 Approach
Figure 1 illustrates the approach that was taken to conduct this study. First, a series of Northwest-
specific data sources were tapped. This included pulling together DR program plans and assessments
from the regulated utilities in the Northwest. In addition, Navigant utilized information about DR
programs and data gaps that was prepared by Navigant for BPA. This data source included a DR
program literature review and results of interviews with several regional stakeholders, including NPCC
staff. Second, Navigant utilized existing information about DR programs from non-Northwest sources
including the WECC study referenced earlier as well as data and information about DR programs that
Navigant has compiled as part of its ongoing DR program development and planning practice. This
included DR program-related information from other utilities outside of the region.
Once the data were pulled together, the next step in the process was to define representative DR
programs. Since NPCC is intending to model capacity-oriented programs for the 7th Power Plan, the
initial focus of the DR programs was to meet capacity needs. Based on the review of DR program
experience, it is apparent that DR for capacity purposes can be fulfilled in one of two ways. The first
(and most common) is for customers to respond to capacity DR events using basic methods to reduce
their loads (e.g., simple switches and manual approaches such as turning off lights and raising/lowering
thermostats). The second is through the use of advanced or so-called Smart DR technologies. With the
advancement of new technologies, we are beginning to see more applications of those technologies
appear in DR programs. Examples include the use of programmable communicating thermostats (PCTs)
for residential heating and cooling applications and automated demand response (AutoDR) measures
tied into energy management control systems in commercial, industrial and agricultural facilities. In
1Note that this report is a revision to a report originally submitted to NPCC on October 24, 2014. This revision
includes estimates of DR potential for summer and winter peak periods. In addition, the total DR potential is
slightly adjusted relative to the original estimates to reflect corrections to some of the modeling computations.
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addition, there is much interest in how DR can be used as a balancing resource for the growing
renewable energy industry. To that end, the various DR programs identified in this exercise that could
potentially accommodate balancing activities were assessed. While not all capacity DR customer
segments or end-uses are ideally suited for balancing purposes, it is appropriate to consider a subset of
the identified programs that could be considered for balancing purposes.
The next step in the process was to develop DR program input parameters. These input parameters
would identify the eligible customer populations for each program, the typical per customer load
impacts that would be realized during various DR events, the costs to enable the customer’s demand
responsiveness in the event that they are deploying Smart DR technologies, and the costs to implement
and operate the DR programs.
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Based on the information obtained, the DR market potential and program cost was estimated through
the development of an Excel-based potential tool. The tool produces results of the forecasted demand
reduction impacts for the Northwest region (as a whole) and the associated yearly cost required to
develop, implement and operate the various DR programs. The tool is included as an attachment to this
report.
By 2030, the estimated DR impact associated with renewable balancing programs that utilize Smart DR
technologies is 275 MWs in the winter and 315 MWs in the summer at an approximate cost of $11.5
million. This yields a unit cost that ranges between $36 and $42 per kW-year. The cumulative load
impact as a percentage of forecast peak demand for the Northwest is 0.7% relative to both the summer
and winter peak.
Balancing Programs
2015 2020 2025 2030
Winter Summer Winter Summer Winter Summer Winter Summer
Total Load Impact (MW) 1 1 243 278 259 297 275 315
Total Load Impact (%) 0.00% 0.00% 0.67% 0.72% 0.68% 0.72% 0.68% 0.70%
Total Program Cost ($) $ 72,438 $ 16,636,820 $ 10,852,975 $ 11,465,038
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includes the costs of program administration, DR program management systems, and evaluation
studies.
• The estimated cumulative DR market potential for capacity programs represents nearly 9% of
winter peak load by 2030. This estimate is in line with estimates of other DR potential studies
conducted both in the Northwest and other parts of the country.
• The DR potential and cost estimates for balancing programs are likely low, due to the limited
data on program experience. Over time, more program experience will allow for more
comprehensive analyses to be conducted for this DR program application.
• This DR market potential assessment was intended to establish a framework by which DR
market potentials could be considered as NPCC develops modeling inputs to support DR-
related forecasts for the Seventh Power Plan. While these preliminary estimates appear to be
reasonable, a multitude of assumptions have gone into the analysis. NPCC would be well
served by taking a more in-depth look at the backup assumptions and analysis contained in the
attached spreadsheet tool.
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2. Representative DR Programs
A total of three representative DR programs were developed for this assessment. The programs cover a
broad range of DR options including Direct Load Control (DLC), Curtailable/Interruptible tariffs, and
Load Aggregator approaches addressing all sectors and a variety of appropriate end-uses. DR programs
and their associated input parameters were developed for the Northwest to address future capacity
needs based on anticipated constraints on the grid as well as for load balancing purposes to address the
growing amount of variable renewable energy in the Northwest. Table 2 presents a matrix of the three
DR program options (as defined by the various customer segments), and their applicability for
addressing capacity and balancing needs. Note that for capacity-based programs two deployment
options are considered: one where more traditional or manual means of achieving load curtailments are
utilized and the second where advanced or so-called Smart DR technologies are applied. For balancing
services, all DR program scenarios also consider the use of Smart DR technologies since curtailment calls
are more frequent with very short notification windows and thus are not conducive to using manual
means for achieving the load curtailments.
Capacity
With Balancing
DR Program Type With Basic
Advanced Services
Technology
Technology
1. Residential DR X X X
2. Commercial DR X X X
3. Industrial/Agricultural DR X X X
2.1.1 Description
There are a variety of DR programs that could be targeted at residential customers. This includes Direct
Load Control (DLC), Peak Time Rebates, and Dynamic Pricing. Of the three, the most common is DLC.
DLC programs allow a utility to interrupt or cycle electrical equipment remotely during load peak times.
DLC for air conditioning units is achieved through cycling units on-and-off or making thermostat
adjustments throughout different times of the day. DLC has traditionally been used to turn on and off
residential air conditioning compressors which typically make up 70% of the electrical load of a
residential air conditioning system. 2
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There are a number of on-going studies evaluating and developing communication and control
mechanisms and infrastructures for direct load control of residential refrigerators for demand response,
but it is assumed that this type of demand response program is currently not yet in place.3
Examples of utilities that offer residential DR programs using traditional switch-based technologies
include:
• Avista
o From 2007 to 2009, Avista conducted a residential DLC pilot in approximately 100
volunteer households. DLC devices were installed on heat pumps, water heaters, electric
force-air furnaces and air conditioners to control operations during 10 scheduled events
at peak times ranging from two to four hours. For a separate study pilot, Avista installed
in-home display devices for a group of customers within the same communities. The
aim of the study was to receive near-real time energy usage feedback from these
customers.4
• Idaho Power
o Idaho Power runs an air conditioner cycling program in which residential customers can
sign up to install a control switch near their A/C units. This program enables A/C units
to be cycled on-and-off on summer days when electricity demand is at its peak.5
• Puget Sound Energy (PSE)
o From 2009 to 2011, PSE implemented a space and water heating DLC pilot.6,7
7 2011 EM&V Report for the Puget Sound Energy Residential Demand Response Pilot Program (Navigant)
http://pse.com/inyourcommunity/kitsap/Documents/BainbridgeIslandDemandResponseProject.pdf
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• Central Electric Cooperative (CEC) [BPA pilot]8,9
o CEC concluded a pilot that turned off water heaters from 5 a.m. to 9 a.m. daily, seven
days a week. The pilot used DLC controls for water heaters, and gave homeowners the
option to override the controls at any point in time.
• Alliant Energy
o Alliant’s runs the “Appliance Cycling Program”, which allows customers to sign up for
the installation of a radio-activated switch on central air conditioner at no cost. Alliant
will turn on the radio signal to activate the switch and cycle the AC units if the demand
for electricity hits a critical point. The program runs from May to September on
weekdays and the dates vary in each state of coverage.10
• Florida Power and Light (FPL)
o FPL runs an optional DLC program that allows residential customers to install a two-
way communication system on their air conditioning, space heating, and water heating
units, as well as swimming pool pumps.
11 https://www.avistautilities.com/inside/resources/irp/electric/Documents/Avista_2013_Electric_IRP_Final.pdf
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o KEC implemented the “Peak Project” program, which provided homeowners with a
programmable thermostat and water heater controls to curtail heating and cooling
equipment at specific times of peak demand.
• Milton-Freewater City Light & Power
o Milton-Freewater City Light & Power offers homeowners the option to install small
signal-receiving units on their water heaters, central heating units, and air conditioners.
Their current program allows all customers to replace their existing one-way load
control units with two-way communication units at no cost. Customers participating in
this program receive discounts on their electric bill.12
• Orcas Power & Light Cooperative (OPALCO) [BPA pilot]
o OPALCO installed residential water heater DR controls in 410 homes in Orcas and San
Juan Island, and is in the process of running DR events.
12 http://www.mfcity.com/conservation#rems
13 http://www.bpa.gov/EE/Technology/demand-response/Pages/residential_demand_response.aspx
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The pilot includes thermal storage furnaces and space and water heater control devices
from Steffes Corporation.
2.2.1 Description
The types of DR programs that could be targeted to commercial customers are typically split into two
categories based on customer size. The first is focused on small commercial facilities (typically with
peak demands that are less than 50 kW). In this case, customers with cooling systems that can be
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controlled either through a conventional switch or through a PCT are targeted. Other end-uses such as
space heating and water heating tend to not be ideally suited to the small commercial customer class,
even in the Northwest. This is due to relatively small saturations or minimal per-customer impacts
making such DR program efforts not worthwhile. The second category is focused on medium-sized
commercial facilities (typically with peak demands that range from 50 kW to 200 kW). In these cases,
customers with cooling systems that can be controlled with a conventional switch or through AutoDR
systems are targeted. For large commercial customers (e.g., with peak demands greater than 200 kW), it
is assumed that those customers would fall under an interruptible tariff or load aggregator program
(addressed in the industrial/agricultural section).
Lighting applications for DR are also considered for medium commercial customers. In these cases, the
customer is presumed to have some type of lighting control system that can easily be adapted to receive
remote signals that initiate a DR event sequence.
Examples of utilities that offer commercial DR programs using traditional switch-based technologies
include:
• PacifiCorp / Rocky Mountain Power
o PacifiCorp’s Rocky Mountain Power currently offers the Cool Keeper Program in Utah,
which provides participating residential and qualifying small commercial customers
with bill credits in exchange for curtailing their cooling loads during the high demand
summer peak. The program is administered by Comverge on a pay-for-performance
contract.
• Florida Power and Light (FPL)
o FPL runs an optional DLC program for businesses that allows for cycling of air
conditioning systems for short periods of time during times of high electricity demand.
The program is achieved through the installation of a two-way automatic
communication system to control air conditioning units.
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• Xcel Energy
o Xcel Energy offers customers the “Saver’s Switch”, a switch product that cycles air
conditioning units during peak periods, typically between 2 p.m. and 7 p.m. on
weekdays. Switches installed prior to 2004 use a 50% cycling strategy during the control
period, while switches installed after 2004 use an adaptive algorithm that allows
customers to achieve a 50% reduction in load based on different usage patterns
throughout the day. As of December 31, 2012, about 96% of the 167,000 currently
installed switches use the adaptive algorithm strategy. Customers may have their air
conditioning controlled for up to four hours between either 2 p.m. to 6 p.m. or 3 p.m. to
7 p.m. on a control day.15
Technologies that fall into the Smart DR category would be aimed at PCTs for small commercial cooling
applications and AutoDR for medium cooling. As mentioned earlier, advanced lighting controls are
looked at for Smart DR and Balancing DR program options.
15 2014 Demand-Side Management Plan, Electric and Natural Gas. Xcel Energy, 2013.
http://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/2014-CO-DSM-Plan.pdf
16 http://www.bpa.gov/EE/Technology/demand-response/Pages/Commercial-and-Industrial.aspx
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o Component B: Cooling for medium commercial
• Commercial DR (Capacity)-with advanced or Smart DR technology
o Component A: Cooling for small commercial (w/ PCT)
o Component B: Cooling for medium commercial (w/ AutoDR)
o Component C: Lighting controls
• Commercial DR (Balancing)-with advanced or Smart DR technology
o Component A: Cooling for medium commercial (w/ AutoDR)
o Component B: Lighting controls
2.3.1 Description
Industrial and agricultural DR programs have been in place for many years. For agricultural
applications, the DR programs have focused exclusively on direct load control measures for water
pumping and irrigation. For industrial, the DR program focus for many years has been on a passive
tariff approach known as curtailable/interruptible. In more recent years, load aggregator approaches
have become a preferable alternative to curtailment approaches as many utilities prefer to procure
demand reductions to third-party entities like EnerNOC who are contractually obligated to deliver load
reductions through customer aggregation approaches.
DR programs for direct load control of irrigation pumps may include a scheduled component, where
customers subscribe in advance for specific days and number of hours their irrigation systems may be
turned off, along with a dispatchable component, where irrigation pumps are controlled for a specific
time period during each event.17
Under a curtailable/interruptible tariff options, eligible customers agree to reduce their demands by a
specific amount or curtail their consumption to a pre-specified level. In return, they receive a fixed
incentive payment in the form of capacity credits or reservation payments (typically expressed as $/kW-
month or $/kW-year) and are paid to be on call even though actual load curtailments may not occur. The
amount of the capacity payment typically varies with the load commitment level. In addition to the fixed
capacity payment, participants receive a payment for energy reduction. Enrolled loads represent a firm
resource and can be counted toward installed capacity requirements. Since load reductions must be of
firm resource quality, curtailment is mandatory and penalties are assessed for under-performance or
non-performance.
Assessment of Long-Term System-Wide Potential for Demand-Side and Other Supplemental Resources, 2013-2032
17
Volume I. (Cadmus)
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Load Aggregators (LAs) are customers or third-party contractors that combine a utility’s customer loads
and make them available for reductions or interruption. Fundamentally, LAs serve two primary
functions in the markets in which they operate. First, by pooling together individual sites into a single
portfolio, LAs are able to increase the reliability of demand response and ensure that the requirements
set forth by utilities can be met. Second, this portfolio approach allows smaller customers below the
minimum size threshold for direct market participation to provide demand response to the market and
receive compensation for their efforts. Of course, LAs may also provide other associated services, such as
identification of curtailable loads and installation of control equipment, but those characteristics will
differ among the various LAs and the markets they operate in.
Examples of agricultural DR programs that use DLC approaches applied to irrigation pumping loads: 18
• Idaho Power
o Idaho Power offers the “Irrigation Peak Rewards Program” for the irrigation season
(June 15 through August 15 for 2014). The Peak Rewards Program allows customers to
receive a financial incentive in exchange for remotely turning off specific irrigation
pumps a minimum of three times during the program season. The program is available
to all Idaho Power agricultural irrigation customers with existing load control devices
installed on their equipment, as well as existing participants classified as Large Service
Locations.19
• PacifiCorp
o PacifiCorp offers the Irrigation Load Control Program in Utah and Idaho. The Irrigation
Load Control program was offered in 2013 to irrigation customers receiving electric
service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service. As of the
2013 program season, EnerNOC manages the irrigation load control program through a
pay-for-performance structure, which allows enrolled participants to receive
participation credit in exchange for curtailment of their electricity usage. Irrigation
equipment is typically set up with a dispatchable two-way control system, which gives
EnerNOC control over the irrigation loads. Participants are given a day-ahead
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notification in advance of control events and have the choice to opt-out of a limited
number of dispatch events each season.20
• Bonneville Power Administration (BPA)
o BPA signed a one-season demonstration agreement with United Electric Cooperative to
evaluate the ability of the Southwest Irrigation District system to increase pumping
during light load hours. The 2014 project kicked-off in early March and will conclude
months later in November.21
Examples of utilities that offer load curtailment or interruptible tariff mechanisms for large industrial
and commercial customers:
• Idaho Power
o FlexPeak Management gives customers the flexibility to manage their business’s peak
demand and electricity usage. Through the “FlexPeak Management” program,
commercial and industrial customers reduce their power usage during times of system
peak demand. Customers who wish to participate are open to enroll through EnerNOC,
a third-party developer and provider of energy solutions. The program enables
participants to work directly with EnerNOC to identify the best ways their business can
shift or reduce energy demand during days when the demand for electricity is at its
highest.22
• Eugene Water & Electric Board (EWEB) [BPA Pilot]
o EWEB’s proposal goal is to demonstrate how pumping stations, coupled with storage,
can be used for decreasing and increasing load. This program aims to show how a utility
can leverage its SCADA system to dispatch DR resources, and to document what types
of loads, including what characteristics are required for load-following resources. The
proposed pilot program can be scaled to other Pumping Stations and Water Authorities
in BPA's region, and prove how storage can be used by these C&I customers to provide
value to the grid both locally and to BPA. More importantly the pilot will demonstrate
whether loads can be used for addressing the intermittency of wind and these impacts
on the grid, and how loads can be used to release the grid of overcapacity.23
20 Utah Energy Efficiency and Peak Reduction Annual Report. Rocky Mountain Power (PacifiCorp), 2014
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Demand_Side_Management/2014/2013-
UT-Annual-Report-FINAL-Report-051614.pdf
21 http://www.bpa.gov/EE/Technology/demand-response/Pages/Agricultural.aspx
22 https://www.idahopower.com/energyefficiency/Business/Programs/FlexPeak/default.cfm
23 http://www.bpa.gov/EE/Technology/demand-response/Pages/Commercial-and-Industrial.aspx
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• MidAmerican Energy
o The utility uses Itron’s curtailment and consumer engagement solutions to help manage
its DR programs.24
• Pacific Gas and Electric (PG&E)
o PG&E offers the “Base Interruptible Program”, which pays an incentive to reduce a
facility’s load to or below a level that is pre-selected by the customer. The program gives
customers a 30 minute advance notice and pays between $8.00/kW to $9.00/kW per
month incentive. Monthly incentive payments are received if no events are called,
however, failure to reduce load down to or below the pre-selected level during an event
will result in a charge of $6.00/kWh for any energy use above the pre-selected level.25
• Sacramento Municipal Utility District (SMUD)
o Commercial customers can sign up for SMUD’s “Voluntary Emergency Curtailment
Program”, in which the utility asks the customers to reduce their energy use by a pre-
determined amount during an emergency energy shortage in the summer. Enrollment is
voluntary, and participating customers get recognized through a public “thank you” by
the utility’s partner publications.26
24 https://itron.com/na/newsAndEvents/Pages/Itron-Customers-Successfully-Implement-Demand-Response-
Programs.aspx
25 http://www.pge.com/en/mybusiness/save/energymanagement/bip/index.page
26 https://www.smud.org/en/business/save-energy/energy-management-solutions/energy-curtailment.htm
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program. In some instances, more advanced irrigation control systems are in place, which can easily be
adapted to accommodate AutoDR systems that will allow for automated irrigation load control
programs. AutoDR consists of fully automated signaling from the utility to provide automated
connectivity to customer end-use control systems, devices and strategies. AutoDR does not require full
automation on the customer end.27 These programs typically require a higher level of trained expertise
to interface with each different customer’s system and ensure interoperability.
For industrial facilities, AutoDR systems would be deployed to ensure greater reliability of DR event
performance. AutoDR systems would be essential for any of the balancing programs considered in this
analysis.
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3. DR Program Results
Table 3. DR Market Potential for Northwest Capacity Programs with Basic Technology
Capacity - Base
2015 2020 2025 2030
Winter Summmer Winter Summmer Winter Summmer Winter Summmer
Load Impact (MW)
Residential
a. Space Cooling - CAC Switch 0.00 7.71 0.00 99.60 0.00 106.33 0.00 112.66
b. Space Cooling - RAC Switch 0.00 0.35 0.00 4.48 0.00 4.78 0.00 5.07
c. Space Heating - Switch 21.09 0.00 272.35 0.00 290.72 0.00 308.03 0.00
d. Water Heating - Switch 21.86 21.86 470.42 470.42 502.16 502.16 532.06 532.06
Total 42.96 29.92 742.77 574.51 792.89 613.27 840.09 649.79
Commercial
a. Space Cooling, Small - Switch 0.63 1.27 8.13 16.26 8.67 17.33 9.19 18.38
b. Space Cooling, Medium - Switch 1.69 3.39 21.77 43.54 23.21 46.42 24.62 49.23
Total 2.33 4.65 29.90 59.80 31.88 63.76 33.81 67.61
Agricultural / Industrial
a. Irrigation Pumping - Switch 0.38 0.43 8.20 9.11 8.74 9.71 9.27 10.30
b. Curtailable/Interruptible Tariff 24.10 24.10 516.03 516.03 550.19 550.19 583.47 583.47
Total 24.48 24.52 524.23 525.14 558.93 559.90 592.73 593.76
GRAND TOTAL 69.76 59.10 1,296.89 1,159.44 1,383.70 1,236.93 1,466.64 1,311.16
Table 4 summarizes the associated cost for the same set of DR programs that make up the capacity
scenario with basic technologies. The total cost of $28.1 million by 2030 yields an estimated 1,467 MWs
of peak load reduction in the winter, at a unit cost of $19/kW-year. The largest contributor to the total
cost comes from residential DR programs.
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Table 4. DR Program Cost for Northwest Capacity Programs with Basic Technology
Capacity - Base
2015 2020 2025 2030
Estimated Program Cost ($)
Residential
Enablement Costs $ 8,308,593 $ 23,243,572 $ 1,912,496 $ 1,771,710
Implementation Costs $ 1,020,344 $ 16,937,063 $ 18,079,924 $ 19,156,419
Total Program Cost $ 9,328,937 $ 40,180,636 $ 19,992,420 $ 20,928,130
Commercial
Enablement Costs $ 365,245 $ 752,013 $ 63,065 $ 58,009
Implementation Costs $ 46,535 $ 597,969 $ 637,554 $ 676,111
Total Program Cost $ 411,781 $ 1,349,982 $ 700,618 $ 734,120
Agricultural / Industrial
Enablement Costs $ 19,694 $ 421,774 $ 449,694 $ 476,890
Implementation Costs $ 245,206 $ 5,251,401 $ 5,599,035 $ 5,937,646
Total Program Cost $ 264,900 $ 5,673,174 $ 6,048,729 $ 6,414,537
GRAND TOTAL $ 10,005,618 $ 47,203,792 $ 26,741,767 $ 28,076,787
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Table 5. DR Market Potential for Northwest Capacity Programs with Smart DR Technology
Capacity - Smart
2015 2020 2025 2030
Winter Summmer Winter Summmer Winter Summmer Winter Summmer
Load Impact (MW)
Residential
a. Space Cooling - CAC PCT 0.00 7.71 0.00 232.41 0.00 248.09 0.00 262.86
b. Space Cooling - RAC PCT 0.00 3.47 0.00 104.58 0.00 111.64 0.00 118.29
c. Space Heating - PCT 21.09 0.00 635.48 0.00 678.36 0.00 718.75 0.00
d. Water Heating - WH Controls 2.43 2.43 52.27 52.27 55.80 55.80 59.12 59.12
Total 23.52 13.62 687.75 389.26 734.15 415.53 777.87 440.27
Commercial
a. Space Cooling, Small - PCT 0.32 0.63 9.48 18.96 10.11 20.22 10.72 21.44
b. Space Cooling, Medium - AutoDR 3.39 6.78 101.60 203.19 108.32 216.64 114.87 229.75
c. Lighting Controls - AutoDR 7.40 7.40 158.48 158.48 168.98 168.98 179.19 179.19
Total 11.10 14.81 269.56 380.64 287.41 405.84 304.79 430.38
Agricultural / Industrial
a. Irrigation Pumping - AutoDR 0.19 0.21 4.10 4.55 4.37 4.85 4.63 5.15
b. Curtailable/Interruptible - AutoDR 24.10 24.10 516.03 516.03 550.19 550.19 583.47 583.47
c. Load Aggregator - AutoDR 6.02 6.02 129.01 129.01 137.55 137.55 145.87 145.87
d. Refrigerated Warehouses - Controls 10.84 12.05 232.22 258.02 247.59 275.10 262.56 291.73
Total 41.15 42.38 881.35 907.61 939.70 967.69 996.53 1,026.22
GRAND TOTAL 75.78 70.80 1,838.66 1,677.52 1,961.26 1,789.07 2,079.18 1,896.87
Table 6 summarizes the associated cost for the same set of DR programs that make up the capacity
scenario with Smart DR technologies. The total cost of $211.7 million by 2030 yields an estimated 2,079
MWs of peak load reduction in the winter, at a unit cost of $101.83/kW-year. The largest contributor to
the total cost comes from enablement technologies associated with residential DR programs.
Table 6. DR Program Cost for Northwest Capacity Programs with Smart DR Technology
Capacity - Smart
2015 2020 2025 2030
Estimated Program Cost ($)
Residential
Enablement Costs $ 18,812,526 $ 195,473,786 $ 140,185,642 $ 147,770,900
Implementation Costs $ 867,736 $ 25,618,560 $ 27,347,221 $ 28,975,499
Total Program Cost $ 19,680,263 $ 221,092,345 $ 167,532,863 $ 176,746,399
Commercial
Enablement Costs $ 3,744,040 $ 15,479,650 $ 1,298,138 $ 1,194,082
Implementation Costs $ 296,194 $ 7,612,845 $ 8,116,803 $ 8,607,681
Total Program Cost $ 4,040,234 $ 23,092,495 $ 9,414,941 $ 9,801,764
Agricultural / Industrial
Enablement Costs $ 860,945 $ 2,954,372 $ 247,756 $ 227,897
Implementation Costs $ 1,028,307 $ 22,022,492 $ 23,480,345 $ 24,900,361
Total Program Cost $ 1,889,252 $ 24,976,863 $ 23,728,101 $ 25,128,258
GRAND TOTAL $ 25,609,749 $ 269,161,704 $ 200,675,906 $ 211,676,421
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3.3 Results for Balancing Programs with Advanced Technology
Table 7 summarizes the results of the market potential for the balancing programs for each DR program
component considered in the analysis. Note that it is assumed that all balancing programs will deploy
Smart DR technology applications. By 2030, the estimated DR market impact associated with balancing-
based DR programs that utilize Smart DR technologies is 274 MWs in the winter and 315 MWs in the
summer. The bulk of the savings mainly come from two programs: curtailable/interruptible programs
and refrigerated warehouses. It is important to note that the DR potential and cost estimates for
balancing programs are likely low, due to the limited data on program experience.
Table 8 summarizes the associated cost for the same set of DR programs that make up the balancing
scenario. The total cost of $11.5 million by 2030 yields an estimated 275 MWs of peak load reduction in
the winter, at a unit cost of $41.82/kW-year. The largest contributor to the total cost comes from
implementation-related activities associated with agricultural/industrial DR programs.
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Table 8. DR Program Cost for Northwest Balancing Programs
Balancing
2015 2020 2025 2030
Estimated Program Cost ($)
Residential
Enablement Costs $ 16,292 $ 2,016,363 $ 93,376 $ 86,503
Implementation Costs $ 1,127 $ 485,119 $ 517,854 $ 548,687
Total Program Cost $ 17,419 $ 2,501,482 $ 611,230 $ 635,190
Commercial
Enablement Costs $ 25,984 $ 3,794,296 $ 178,145 $ 163,865
Implementation Costs $ 3,158 $ 1,611,273 $ 1,717,937 $ 1,821,832
Total Program Cost $ 29,142 $ 5,405,569 $ 1,896,082 $ 1,985,698
Agricultural / Industrial
Enablement Costs $ 7,699 $ 943,835 $ 44,314 $ 40,762
Implementation Costs $ 18,178 $ 7,785,934 $ 8,301,350 $ 8,803,389
Total Program Cost $ 25,877 $ 8,729,769 $ 8,345,664 $ 8,844,150
GRAND TOTAL $ 72,438 $ 16,636,820 $ 10,852,975 $ 11,465,038
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• The next three tabs (shaded in blue) contain many of the sector-specific inputs and calculations
that generate program-specific load impacts and costs for capacity-based DR programs that
utilize Smart DR enablement technologies.
• The final three tabs (shaded in green) contain many of the sector-specific inputs and calculations
that generate program-specific load impacts and costs for balancing-based DR programs.
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Appendix A. Key Assumptions and Sources
This appendix lists the key assumptions and sources used for the “Key Assumptions” tab in the Excel-
based DR potential tool created for this study.
Technology Costs
• Capacity – Base
o Residential CAC DLC switches = $60 (cost of one-way switch)29
o Residential Room AC DLC switches = $40 (assumes room AC switches are $20 cheaper
than central AC switches due to smaller equipment size)
o Commercial DLC switches = $10030
• Capacity - Smart
o Residential PCTs = ($400/kW * load impact)31
o Water Heater Controls = assumes same technology cost as residential PCTs.
o Commercial PCTs = ($285.71/kW * load impact)31
o Auto DR + Lighting Control System = ($138.50/kW * load impact)31
o Auto DR + Energy Management System = ($138.50/kW * load impact)31
o Auto DR for Curtailable/Interruptible Tariffs = average of costs for customers with and
without a Building Management System (BMS). $2500 on CII side assumes that roughly
50% of customers have BMS and thus their device costs are around $500; the others need
some sort of low-cost BMS or gateway plus points. Does not include labor costs
associated with installation and integration.32
o Auto DR for Load Aggregator = average of costs for customers with and without a
Building Management System (BMS). $2500 on CII side assumes that roughly 50% of
customers have BMS and thus their device costs are around $500; the others need some
sort of low-cost BMS or gateway plus points. Does not include labor costs associated
with installation and integration.
o Refrigerated Warehouse Controls = $5000 (assumes half the cost of BPA’s pilot hardware
cost, $10,00033)
• Balancing
o Assumes same as “Capacity – Smart” technology costs
29 Navigant Research, Demand Response for Residential Markets, RDR-12, 4Q 2012. Does not include labor costs
associated with installation and integration.
30 Navigant analysis conducted for Tucson Electric Power’s mass market DLC program. Does not include costs
33 Bonneville Power Administration Technology Innovation Project 220 - TI 220 Project Evaluation Report, 2012.
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Installation Costs
• Capacity – Base
o Residential DLC switches = ($80/kW * load impact) (Navigant experience-based
estimate)
o Commercial DLC switches = ($60/kW * load impact) (assumes downward trend in
installation cost from residential, based on a larger load offset)
o Industrial DLC switches = ($40/kW * load impact) (assumes downward trend in
installation cost from commercial, based on a larger load offset)
• Capacity – Smart
o Installation Cost for Residential PCTs = ($114.90/kW * load impact)31
o Installation Cost for Water Heater Controls = assumes same installation cost as
residential PCTs
o Installation Cost for Commercial = ($82.07/kW * load impact)31
o Installation Cost for Auto DR + Lighting Control System = ($96/kW * load impact)31
o Installation Cost for Auto DR + Energy Management System = ($96/kW * load impact)31
o Installation Cost for Curtailable/Interruptible Tariff = assumes 50% of the technology
cost
o Installation Cost for Refrigerated Warehouse Controls = assumes 50% of the technology
cost
• Balancing
o Same installation costs as “Capacity – Smart”
Implementation Cost
• Capacity – Base
o Residential DR = $20/kW-yr (Navigant experience-based estimates)
o Commercial and Industrial DR = $10/kW-yr (assumes a 50% derate from residential
estimate, based on scale economies due to larger customers)
• Capacity – Smart
o Residential DR = assumes an additional 25% to the implementation cost of residential
“base” DR programs.
o Commercial and Industrial DR = assumes double the implementation cost of commercial
“base” DR programs.
o Lighting controls = assumes the same implementation cost as other Commercial DR
categories.
o Load Aggregator = $50/kW-yr (Navigant experience-based estimates)
o Refrigerated Warehouses = assumes the same implementation cost as Commercial and
Industrial “Smart” DR programs
• Balancing
o Assumes 50% increase from all “smart” DR programs
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Load Impacts
• Capacity – Base
o Residential Space Heating – DLC = (1.74 kW/customer)34
o Residential Water Heating – DLC = (0.58 kW/customer)34
o Residential Space Cooling – CAC DLC = (0.6 kW/customer)32
o Residential Space Cooling – RAC DLC = (0.27 kW/customer)32
o Commercial Space Cooling, Small – CAC DLC = (2.8 kW/customer)32
o Commercial Space Cooling, Medium – CAC DLC = 15 kW/customer (Navigant
experience-based estimate)
o Agricultural Irrigation Pumping – DLC = 25 kW/customer (Navigant experience-based
estimate)
o Industrial Curtailable/Interruptible Tariffs = 500 kW/customer (Navigant experience-
based estimate)
• Capacity – Smart
o Assumes same load impacts as “Base” DR programs
o Commercial Lighting Controls = 57 kw/customer31
o Industrial Load Aggregator = 100 kw/customer (Navigant experience-based estimate)
o Industrial Refrigerated Warehouses = 250 kw/customer (Navigant experience-based
estimate)
• Balancing
o Assumes same load impacts as “Smart” DR programs
Saturation
• Capacity – Base
o Residential Space Heating – DLC = 33% (assumes 1/3 of homes in the Northwest are
eligible for space heating DLC)
o Residential Water Heating – DLC = 57%Error! Bookmark not defined. (calculated as the
average of single-family and multiplex units water heat saturation results)
o Residential Space Cooling – CAC DLC = 35%35
o Residential Space Cooling – RAC DLC = 18% (assumes half the saturation rate of central
AC)
o Commercial Space Cooling, Small – CAC DLC = 35% (58% of cooling saturation32
multiplied by an assumed 60% of commercial customers being in the small category)
o Commercial Space Cooling, Medium – CAC DLC = 17% (assumes the 58% of cooling
saturation from small commercial cooling and multiplies by an assumed 30% of
commercial customers being in the medium category)
Based on 2009 FERC study saturation data. Federal Energy Regulatory Commission - A National Assessment of
35
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o Agricultural Irrigation Pumping – DLC = 70% (Navigant experience-based estimate)
o Industrial Curtailable/Interruptible Tariffs = 70% (Navigant experience-based estimate)
• Capacity – Smart
o Same as “base” DR programs.
o Commercial Lighting Controls = 25% (assumes 25% of all lighting systems have
automatic controls)
o Industrial Curtailable/Interruptible Tariffs = 35% (assumes 50% saturation levels of
“base” industrial curtailable/interruptible tariffs program)
o Industrial Load Aggregator = 18% (assumes 25% saturation of “base” industrial load
aggregator program),
• Balancing
o Assumes all “smart” DR programs can be enabled for balancing services.
Participation
• Capacity – Base
o Residential DR programs = 25%
Other participation rates were estimated based on the residential participation
rate.
o Commercial DR programs = 15% (based on Navigant assumption that commercial
customers are harder to reach and tend to exhibit smaller participation rates relative to
residential).
o Agricultural DR programs = 20% (based on Navigant assumption that agricultural
customers have similar participation characteristics to residential customers).
o Industrial DR programs = 25% (assumes the same participation rate as residential
programs participation).
o Refrigerated Warehouses = 20% (assumes to be comparable to agricultural customers in
terms of participation).
• Capacity – Smart
o Same as “base” DR programs.
• Balancing
o Same as “base” DR programs.
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o Residential Space Cooling – CAC DLC
Winter = 0% (assumes no load in the winter)
Summer = 100% (assumes the full load in the summer)
o Residential Space Cooling – RAC DLC
Winter = 0% (assumes no load in the winter)
Summer = 100% (assumes the full load in the summer)
o Commercial Space Cooling, Small – CAC DLC
Winter = 50% (assumes commercial AC is still operational during the winter due
to internal heat sources; assumes 50% of the summer load)
Summer = 100% (assumes the full load in the summer)
o Commercial Space Cooling, Medium – CAC DLC
Winter = 50% (assumes commercial AC is still operational during the winter due
to internal heat sources; assumes 50% of the summer load)
Summer = 100% (assumes the full load in the summer)
o Commercial Lighting Controls
Winter = 100% (assumes the full load in the winter)
Summer = 100% (assumes the full load in the summer)
o Agricultural Irrigation Pumping – DLC
Winter = 90% (assumes there is more irrigation activity in the summer than
winter months; assumes 10% less than the summer load)
Summer = 100% (assumes the full load in the summer)
o Industrial Curtailable / Interruptible Tariffs
Winter = 100% (assumes the full load in the winter)
Summer = 100% (assumes the full load in the summer)
o Industrial Load Aggregator
Winter = 100% (assumes the full load in the winter)
Summer = 100% (assumes the full load in the summer)
o Industrial Refrigerated Warehouses
Winter = 90% (assumes the load required in the winter is lower than in the
summer due to a lower temperature differential; assumes 10% less than the
summer load)
Summer = 100% (assumes the full load in the summer)
• Capacity – Smart
o Same as “base” DR programs.
• Balancing
o Same as “base” DR programs.
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