20190315DSM Supplement 1.pdf

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An IDACORP Company
MARCH'l 5 . 2019
DEMAND SlDE MANAGM{T
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SUPPLEMENT I:
Supplement 1 : Cost-Effectiveness ldaho Power Company
TleLe oF GoNTENTS
Supplement I : Cost-Effectiveness 1
1
2
J
6
6
7
Cost-Effectiveness.....
Methodology..
Assumptions...........,
Conservation Adder
Net-to-Gross....
Results......
2018 DSM Detailed Expenses by Program
Cost-Effectiveness Tables by Pro gram
.............10
.............14
.............14Educational Distributions...
Energy Effi cient Lighting...
Energy House CaIIs............
16
Heating & Cooling Efficiency Program.......
..18
..20
..23Multifamily Energy Savings Program
Rebate Advantage .26
.28
.30
.31
.JJ
.34
.35
.37
.40
.45
.54
Residential New Construction Pilot Program...............
Shade Tree Project .....
Simple Steps, Smart Savings'"
Weatherization Assistance for Qualifi ed Customers .....
Weatherization Solutions for Eligible Customers
Commercial Energy-Saving Kits ..........
Custom Projects
New Construction
Retrofits
Irrigation Efficiency Rewards
Page i Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
List of Tables
Table 1.2018 non-cost-effective measures ..................10
Table 2.2018 DSM detailed expenses by program (dollars).... .......................1 I
Table 3. Cost-effectiveness of 2018 programs by B/C test............ ..................14
Page ii Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
SupplEMENT 1 : Gosr-ErrecrrvENESS
Cost-Effectiveness
Idaho Power considers cost-effectiveness of primary importance in the design, implementation, and
tracking of energy efficiency and demand response programs. Idaho Power's energy efficiency and
demand response opportunities are preliminarily identified through the Integrated Resource Plan (IRP)
process. Idaho Power uses third-party energy efficiency potential studies to identify achievable cost-
effective energy efficiency potential, which is added to the resources included in the IRP. Idaho Power's
Program Planning Group (PPG) explores new opportunities to expand current demand-side management
(DSM) programs and offerings.
Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power
performs a preliminary cost-effectiveness analysis to assess whether a potential program design or
measure may be cost-effective from the perspective of Idaho Power and its customers. Incorporated
in these models are inputs from various sources that use the most current and reliable information
available. When possible, Idaho Power leverages the experiences of other utilities in the region and/
or throughout the country to help identify specific program parameters. This is accomplished through
discussions with other utilities'program managers and researchers. Idaho Power also uses electric
industry research organizations, such as E Source, Northwest Energy Efficiency Alliance (I{EEA)
Regional Emerging Technology Advisory Committee, the Consortium for Energy Efficiency (CEE),
American Council for an Energy-Efficient Economy (ACEEE), Advanced Load Control Alliance
(ALCA), and Association of Energy Service Professionals (AESP), to identiff similar programs
and their results. Additionally, Idaho Power relies on the results of program impact evaluations and
recommendations from consultants.
Idaho Power's goal is for all programs to have benefiVcost (B/C) ratios greater than one for the total
resource cost (TRC) test, utility cost test (UCT), and participant cost test (PCT) at the program and
measure level where appropriate. Each cost-effectiveness test provides a different perspective, and Idaho
Power believes each test provides value when evaluating program performance. If a measure or program
is found to be not cost-effective from one or more of the three tests, Idaho Power assesses the program
or measure and runs the cost-effectiveness calculations under a variety of scenarios. There are many
assumptions when calculating the cost-effectiveness of a given program or measure. For some measures
within the programs, savings can vary based on factors such participation levels or the participants'
locations. For instance, heat pumps installed in the Boise area will have less savings than heat pumps
installed in the McCall area. If program participation and savings increase, fixed costs such as labor and
marketing is spread out more and the program cost-effectiveness increases.
When a program or measure is shown to be not cost-effective, Idaho Power works with Energy
Efficiency Advisory Group (EEAG) to get additional input. If the measure or program is indeed offered,
the company explains to stakeholders why the measure or program was implemented or continued and
the steps the company plans to take to improve its cost-effectiveness. The company believes this aligns
with the expectations of the Idaho Public Utilities Commission (IPUC) and Public Utility Commission
Page 1 Demand-Side Management 2018 Annual Report
of Oregon (OPUC)
In IPUC Order No. 33365, page 9, the IPUC states the following
We thus find it reasonable for the Company to continue screening potential programs using
each test as a guideline, and to advise us on how the Company's programs fare under
each test. When the Company ultimately seeks to recover its prudent investment in such
programs, however, we believe the Company may (but need not exclusively) emphasize the
UCT-and that test's focus on Company-controlled benefits and costs-to argue whether
the programs were cost-effective.
In the OPUC Order No. 94-590, issued in Utility Miscellaneous (UM) 551, the OPUC outlines specific
cost-effectiveness guidelines for energy efficiency measures and programs managed by program
administrators. It is the expectation of the OPUC that measures and programs pass both the UCT and
TRC tests. Measures and programs that do not pass these tests may be offered by a utility if they meet
one or more of the following additional conditions specified by Section 1 3 of Order No. 94-590:
A. The measure produces significant non-quantifiable non-energy benefits (NEB)
B. Inclusion of the measure will increase market acceptance and is expected to lead to reduced cost
of the measure
C. The measure is included for consistency with other DSM programs in the region
D. Inclusion of the measure helps increase participation in a cost-effective program
E. The package of measures cannot be changed frequently, and the measure will be cost-effective
during the period the program is offered
F. The measure or package of measures is included in a pilot or research project intended to be
offered to a limited number of customers
G. The measure is required by law or is consistent with OPUC policy and/or direction
If Idaho Power determines a program or measure is not cost-effective but meets one or more of the
exceptions set forth by Order No. 94-590, the company files an exceptions request with the OPUC to
continue offering the measure or program within it its Oregon service area.
For operational and administrative efficiency, Idaho Power endeavors to offer identical programs in both
its Oregon and Idaho jurisdictions. Some customers, contractors, and trade allies operate in both states.
Program consistency is important for the participants'overall satisfaction with the programs. Offering
different program designs would create confusion in the marketplace and could inhibit participation.
In addition, program infrastructure is designed to implement consistent programs across the service area.
Methodology
For its cost-effectiveness methodology, Idaho Power relies on the Electric Power Research Institute
(EPRI) End Use kchnical Assessment Guide (TAG); the California Standard Practice Manual and its
Page2 Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Supplement 1 : Cost-Effectiveness ldaho Power Company
subsequent addendum, the National Action Plan for Energy Efficiency's (NAPEE) Understanding Cost
Effectiveness of Energt Efficiency Programs: Best Practices, kchnical Methods, and Emerging Issues
for Policy-Makers; and the National Action Plan on Demand Response. For resource planning, Idaho
Power uses the TRC test. This test is used because, as defined in the TAG and Califurnia Standard
Practice Manual, it is the most like supply-side tests and provides a useful basis to compare demand-
side and supply-side resources. For program planning and evaluation, the company uses the TRC and the
UCT test to develop B/C ratios to determine the cost-effectiveness of DSM programs. The PCT provides
the company the opportunity to assess a program or measure from the participant perspective and to
determine if it is in the best interest of the average customer.
For energy efficiency programs, each program's cost-effectiveness is reviewed annually from a one-
year perspective. The annual energy-savings benefit value is summed over the life of the measure or
program and is discounted to reflect 2018 dollars. The result of the one-year perspective is shown in
Supplement I : Cost-Effectiveness.
The goal of demand response programs is to minimize or delay the need to build new supply-side
resources. Unlike energy efficiency programs or supply-side resources, demand response programs
must acquire and retain participants each year to maintain a level of demand-reduction capacity for
the company.
As part of the public workshops on Case No. IPC-E,-13-14,Idaho Power and other stakeholders agreed
on a new methodology for valuing demand response. The settlement agreement, as approved in IPUC
Order No. 32923 and OPUC Order No. 13-482, defined the annual cost of operating the three demand
response programs for the maximum allowable 60 hours to be no more than $16.7 million. The annual
value calculation will be updated with each IRP based on changes that include, but are not limited
to, need, capital cost, or financial assumptions. This amount was reevaluated in the 2015 IRP to be
$18.5 million and again in the 2017 IRP to be $19.8 million.
This value is the levelized annual cost of a 170-megawatt (MW) deferred resource over a 20-year life.
The demand response value calculation will include this value even in years when the IRP shows no
peak-hour capacity deficits. In 2018, the cost of operating the three demand response programs was
$8.2 million. Idaho Power estimates that if the three programs were dispatched for the full 60 hours,
the total costs would have been approximately $l1.3 million and would have remained cost-effective.
Assumptions
Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumptions
for various measures. These assumptions are routinely reviewed internally and with EEAG and
updated as new information becomes available. For many of the measures within Supplement I:
Cost-Effectiveness, savings and costs were derived from the Regional Technical Forum (RTF),
the technical reference manual (TRM), or the ldaho Power Energt Efficiency Potentiol Study conducted
by Applied Energy Group (AEG). Idaho Power received end-use load shapes from AEG, which have
been applied to each program and measure when applicable. Idaho Power used updated assumptions
Page 3 Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
from the 2016 potential study for the 201 8 cost-effectiveness analyses. Due to the timing of the 201 8
potential study, Idaho Power will use any updated assumptions from the 201 8 study in 2019.
The RTF regularly reviews, evaluates, and recommends eligible energy efficiency measures and the
estimated savings and costs associated with those measures. For instance, because of the rapid changes
in the lighting market, the RTF is currently evaluating lighting measures on an annual basis. As the
RIF updates these assumptions, Idaho Power applies them to current program offerings and assesses
the need to make any program changes. Idaho Power staffparticipates in the RTF by attending monthly
meetings and contributing to various sub-committees. Because cost data from the RTF information is in
2012 dollars, measures with costs from the RTF are escalated to 2018 dollars. The costs are escalated by
7.8 percent. This percentage is provided by the RTF in workbook RTFStandardlnformationWorkbook
v3 2.xlsx.
Idaho Power uses a TRM developed by ADM Associates, Inc. for the Commercial and Industrial
Energy Efficiency Program's New Construction and Retrofit options. In 2018, the company contracted
with ADM to update the TRM. Idaho Power also relies on other sources, such as the Northwest Power
and Conservation Council (I.{WPCC), Northwest Energy Efficiency Alliance (NEEA), the Database
for Energy Efficiency Resources (DEER), the Energy Trust of Oregon (ETO), the Bonneville Power
Administration (BPA), third-party consultants, and other regional utilities. Occasionally, Idaho Power
will also use internal engineering estimates and calculations for savings and costs based on information
gathered from previous projects.
The company freezes savings assumptions when the budgets and goals are established for the next
calendar year unless code and standard changes or program updates necessitate a need to use updated
savings. These assumptions are discussed in more detail in the cost-effectiveness sections for each
program. As a rule, the 2018 energy savings reported for most programs will use the assumption set
at the beginning of the year. An exception would be the Commercial & Industrial Energy Efficiency
program. Once the TRM was updated, the company launched changes to the program inAugust 2018.
For applications initiated before the change date, the TRM version 1.7 was the source for most savings
and cost assumptions for the New Construction and Retrofit options. For applications initiated after the
change date, the current TRM version 2.2 is the source for most savings and cost assumptions for the
program.
The remaining inputs used in the cost-effectiveness models are obtained from the IRP process.
Idaho Power's 2015 IRP was acknowledged by the IPUC on December 23,2015 and by the OPUC
April 28, 2016 and is the source of all the financial assumptions for the cost-effectiveness analysis.
Appendix C-Tbchnical Appendix of Idaho Power's 2015 IRP contains the DSM alternative costs,
discount rate, and escalation rate. These DSM alternative costs vary by season and time of day and are
applied to an end-use load shape to obtain the value of that particular measure or program. The DSM
altemative energy costs are based on both the projected fuel costs of a peaking unit and forward
electricity prices as determined by Idaho Power's power supply model, AURORAxmp@ Electric Market
Model. The avoided capital cost of capacity is based on a gas-fired, simple-cycle turbine. In the 2015
IRP, the annual avoided capacity cost is $119 per kilowatt (kW).
Page 4 Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
As part of the 2015 IRP Case IPC-E-15-19 and2014 DSM prudence Case IPC-E-15-06, parties
requested Idaho Power review how transmission and distribution (T&D) costs are treated in the IRP.
Idaho Power committed to reviewing the T&D beneflts, and the analysis was presented to EEAG in
August 2016. The estimated average value of energy efficiency on T&D deferral is $3.76lkW per year or
$0.000429/kilowatt-hour (kwh). In compliance with Order No. 33365, this value is escalated and added
to the 2015 DSM alternative energy costs and included in the cost-effectiveness analysis for 2018.
Idaho Power's 2017 IRP was filed on June 30,2017 with the IPUC under case IPC-E-l7-ll and with
the OPUC under case LC 68. Idaho Power's 2017IRP was acknowledged by the IPUC on February 9,
2018 in Order No. 33983 and in by the OPUC on May 23,2018 in Order No. 18-176. Since the2017
IRP was acknowledged after the budgets and goals were set for 2018, the 2015 IRP remained the source
for all financial assumptions and cost-effectiveness analysis in 201 8. The 20 I 7 IRP is expected to be the
source of all assumptions and analysis for the 2019 program year. For the demand response programs,
with inputs from the 20l7IRP, the Company determined the maximum annual cost of running all three
demand response programs for the maximum allowable hours of 60 hours has been calculated to be no
more than $19.8 million.
As recommended by the NAPEE Understanding Cost-Effectiveness of Energt Efficiency Programs,
Idaho Power's weighted average cost of capital (WACC) of 6.74 percent is used to discount future
benefits and costs to today's dollars. Once the DSM alternative costs and load shapes are applied to
the annual kWh savings of a measure or program, the WACC is used to calculate the net present value
(NPV) of the annual benefit for the UCT and TRC B/C ratios. However, determining the appropriate
discount rate for participant cost and benefits is difficult because of the variety of potential discount
rates that can be used by the different participants as described in the TAG. Since the participant benefit
is based on the anticipated bill savings of the customer, Idaho Power believes the WACC is not an
appropriate discount rate to use. Because the customer bill savings is based on Idaho Power's 2018
average customer segment rate and is not escalated, the participant bill savings is discounted using a real
discount rate of 4.44 percent, which is based on the 2015 IRP's WACC of 6.74 percent and an escalation
rate of 2.2 percent. The real discount rate is used to calculate the NPV of any participant benefits or costs
for the PCT or ratepayer impact measure (RIM) B/C ratios.
The formula to calculate the real discount rate is as follows:
((1 + WACC) + (l + Escalation)) - 1 : Real
Line-loss percentages are applied to the metered-site energy savings to find the energy savings at the
generation level. The Demqnd-Side Management 2018 Annual Report shows the estimated electrical
savings at the customer meter level. Cost-effectiveness analyses are based on generation-level energy
savings. The demand response program reductions are reported at the generation level with the line
losses. The average system line-loss factor is 9.6 percent while the summer peak line-loss factors is
9.7 percent.
Page 5 Demand-Side Management 20'18 Annual Report
Gonservation Adder
The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act) states
the following:
. . .any conservation or resource shall not be treated as greater than that of any
non-conservation measure or resource unless the incremental system cost of such
conservation or resource is in excess of 1 l0 per centum of the incremental system cost
of the nonconservation measure or resource.
As a result of the Northwest Power Act, most utilities in the Pacific Northwest add a 10-percent
conservation adder in energy efficiency cost-effectiveness analyses. In OPUC Order No. 94-590,
the OPUC states:
We support the staffs position that the effect of conservation in reducing uncertainty
in meeting load growth is included in the ten percent cost adder and that no separate
adjustment is necessary.
Additionally, in IPUC Order No. 32788 in Case No. GNR-E-12-0L, "Staffnoted that Rocky Mountain
Power and Avista use a 10 percent conservation adder when calculating the cost-effectiveness of all
their DSM programs." Staff recommended the utilities have the option to use a lO-percent adder, and
the IPUC agreed with the recommendation to allow utilities to use the 1O-percent adder in the cost-
effectiveness analyses for low-income programs.
After reviewing the practices of other utilities in the Pacific Northwest, as well as the OPUC Order
No. 94-590 and IPUC Order 32788,ldaho Power applies the l0-percent conservation adder in all
energy efficiency measure and program cost-effectiveness analyses when calculating the TRC test.
Net-to-Gross
Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE's Understanding Cost
Effectiveness of Energt Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues
for Policy-Makers as a ratio that does as follows:
Adjusts the impacts of the programs so that they only reflect those energy efficiency gains
that are the result of the energy efficiency program. Therefore, the NTG deducts energy
savings that would have been achieved without the efficiency program (e.g., 'free-riders')
and increases savings for any 'spillover'effect that occurs as an indirect result of the
program. Since the NTG attempts to measure what the customers would have done in the
absence of the energy efficiency program, it can be difficult to determine precisely.
Capturing the effects of Idaho Power's energy efficiency efforts on free-ridership and spillover
is difficult. Due to the uncertainty surrounding NTG percentages, Idaho Power used an NTG of
Supplement 1 : Cost-Effectiveness ldaho Power Company
Page 6 Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
100 percent for all measure cost-effectiveness analyses. For the program cost-effectiveness analyses,
the B/C ratios shown are based on a 10O-percent NTG. A sensitivity analysis was conducted to show
what the minimum NTG percentage needs to be for the program to remain (or become) cost-effective
from either the TRC or UC perspective. These NTG percentages are shown in the program
cost-effectiveness results in Supplement I : Co s t- Effi ctivene s s.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis.
As part of Supplement I : Cost-Effectiveness and where applicable, Idaho Power publishes the
cost-effectiveness by measure, calculating the PCT and RIM test at the program level, listing the
assumptions associated with cost-effectiveness, and citing sources and dates of metrics used in the
cost-effectiveness calculation.
The B/C ratio from the participant cost perspective is not calculated for the Commercial Energy-Saving
Kits, Educational Distributions, Energy House Calls, Multifamily Energy Savings Program, Shade Tree
Project, Weatherization Assistance for Qualified Customers (WAQC), and Weatherization Solutions for
Eligible Customers programs. These programs have few or no customer costs. For energy efficiency
programs, the cost-effectiveness models do not assume ongoing participant costs.
Supplement I : Cost-Effectiveness contains annual cost-effectiveness metrics for each program using
actual information from 2018 and includes results of the UCT, TRC, PCT, and RIM. Current average
customer energy rates are used in the calculation of the B/C ratios from a PCT and RIM perspective.
Rate increases are not forecasted or escalated. A summary of the cost-effectiveness by program can be
found in Table 3.
In 2018, most of Idaho Power's energy efficiency programs were cost-effective, except for Heating &
Cooling Efficiency (H&CE) Program, Shade Tree Project, and the weatherizationprograms for
income-qualifi ed customers.
The H&CE Program has a UC of 1.65, TRC of 0.83, PCT of 1.50. Idaho Power first notified EEAG
in August 2016 that the program was anticipated to be not cost-effective from the TRC perspective.
Idaho Power has continued to update EEAG of its efforts to improve the program's cost-effectiveness
Throughout2}lT and into 20l&,Idaho Power worked toward improving program cost-effectiveness.
These tactics included: l) reassigning non-program labor, 2) reducing marketing spend while improving
other tactics, 3) reducing contractor incentives from $150 to $50, and 4) adding heat pump water heaters
to the program. These efforts were successful in keeping cost-effectiveness ratios from falling in 2018
over 2017 levels. However, calibrations to end-use load shapes created for the 2016 energy efficiency
potential study offset cost-effectiveness gains from cost control efforts in 2018. Had Idaho Power used
the same load shape as was used for the 2017 program year, the program would have had a TRC just
over 1.0.
PageT Demand-Side Management 2018 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Due to their high costs, DHPs continue to bring down the cost-effectiveness of the program. The DHP
portion of the program has a UCT of 1.37 and TRC 0.69 while the rest of the program has a UCT of 1.82
and TRC of 0.96. Market transformation efforts, specifically the market transformation work provided
by NEEA, in the region have failed to drive prices down along with lower net savings in colder climates
are the two primary problems plaguing DHP cost-effectiveness.
When the company began the Shade Tree Projectin2013, the initial analysis showed that the project
would be cost-effective from the UCT and TRC perspective based on preliminary assumptions and
then-current DSM alternate costs. The company's intent was to begin claiming savings when the
original planted trees were flve years old. Since the Shade Tree Project began in2013,2018 was the
first year Idaho Power claimed savings and calculating the cost-effectiveness for the Shade Tree Project.
This project is shown to have a UCT of 0.71, a TRC of 0.80. The cost-effectiveness for the program is
based on the modeled savings for the tree distributed in 2018 and the costs incurred during 2018. It is
estimated that these trees will begin saving 35,425 kWh in 2022 and 116,197 kWh by year 2038.
DNV GL created a new savings model to adjust the savings from the enrollment calculator using the
data from Idaho Power's 2015-2017 audit of the project. The audit provided information on where
the trees were actually planted and the tree mortality. The new savings model calculates the average
savings per tree and assumed a measure life of 20 years. This is because the enrollment software,
i-Tree, used by the Arbor Day Foundation only estimates saving at 5, 10, I 5, and 20 years. In 2018, the
bur oak, northern red oak, Greenspire@ littleleaf linden, and tulip tree were the most common species
distributed in the project. According to the United States Department ofAgriculture and the Urban
Forest Ecosystem Institute, these trees can live up to 500 years. Idaho Power acknowledges that the
potential energy savings for a tree may continue to increase beyond year 20, but the savings will be
capped at some point regardless of how large the tree grows. For trees distributed in 2018, data around
the survivorship of the tree beyond 2038 is also unknown.
While the energy saving in 2038 is estimated to be 116,197 kwh, the savings may continue to increase
at a diminishing rate before eventually declining due to increased mortality. However, if energy savings
were to stay constant beyond year 20, it can be assumed that program would be cost-effective from the
UCT and TRC perspective if the program life was revised to 30 years.
WAQC had a TRC of 0.52 and a UCT ratio of 0.43, and Weatherization Solutions for Eligible Customers
had a TRC of 0.51 and a UCT ratio of 0.37. The programs'cost-effectiveness ratios increased slightly
over 2017's ratios. To calculate the programs' cost-effectiveness, Idaho Power adopted the following
IPUC staffs recommendations from Case No. GNR E-12-01:
Applied a 100-percent NTG
Claimed 100 percent of energy savings for each project.
Included indirect administrative overhead costs. The overhead costs of 3.017 percent were
calculated from the $1,335,208 of indirect program expenses divided by the total DSM expenses
of $44,262,080 as shown inAppendix 3 of the Demand-Side Management 2018 Annual Report.
Page 8 Demand-Side Management 2018 Annual Report
a
a
a
Supplement 1 . Cost-Effectiveness ldaho Power Company
Applied the l0 percent conservation preference adder.
Amortized evaluation expenses over a three-year period
Claimed one dollar of NEBs for each dollar of utility and federal funds invested in health,
safety, and repair measures.
Eighteen ouit of 279 individual measures in various programs are shown to not be cost-effective from
either the UCT or TRC perspective. These measures will be discontinued, analyzed for additional
NEBs, modified to increase potential per-unit savings, or monitored to examine their impact on the
specific program's overall cost-effectiveness. Specifically, of the 18 non-cost-effective measures,
and seven have ratios between 0.90-0.99 and three have ratios between 0.80-0.89. For most of these
measures, Idaho Power flled cost-effectiveness exception requests with the OPUC in compliance with
Order No. 94-590. Measures and programs that do not pass these tests may be offered by the utility
if they meet one or more of the additional conditions specifled by Section 13 of Order No. 94-590.
These exception requests were approved under Order No. 15-200 on June 23,2015, or with the specific
program advice filings. The filings and exception requests are noted in Table 1.
Table 1 .2018 non-cost-effective measures
o
o
Program
Number of
Measures Notes
H&CE Program 7 Cost-effectiveness exception request for ductless heat pumps (DHP) and open-loop
water source heat pumps filed with the OPUC under UM-1710. OPUC Order No. 94-
590, Section 13. Approved under Order No. 15-200. Exception request for the program
and smart thermostat requested and approved with OPUC Advice No. 17-09. Heat
pump water heaters and duct sealing measures would be cost-effective at 1.00 and
1.16 respectively without the inclusion of administration costs. Meets OPUC Order No.
94-590, Section 10.
Rebate Advantage 1 Eco-Rated manufactured homes built in Heatin g Zone 1 and Cooling Zone 3 has a TRC
of 0.97. Measures would be cost-effective with TRC of 1 .1 0 without the inclusion of
administration costs. Meets OPUC Order No. 94-590, Section 10.
New Construction 5 Measures offered in both options. Cost-effectiveness exception request filed and
and Retrofits approved with OPUC Advice No. '18-08. OPUC Order No. 94-590, Section 13.
Exceptions B, C, and D.
Retrofit 5 UCT and TRC ranges from 0.85 to 0.97. Cost-effectiveness exception request filed
and approved with OPUC Advice No. 18-08. OPUC Order No. 94-590, Section 13.
Tn
Following the annual program cost-effectiveness results are tables that include measure-level
cost-effectiveness. Exceptions to the measure-level tables are programs that are analyzed at the project
level. These programs include Custom Projects, the custom option of Inigation Efficiency Rewards,
Shade Tree, WAQC, and Weatherization Solutions for Eligible Customers.
The measure-level cost-effectiveness includes inputs of measure life, energy savings, incremental
cost, incentives, program administration cost, and net benefit. Program administration costs include all
non-incentive costs: labor, marketing, training, education, purchased services, and evaluation. Energy
and expense data have been rounded to the nearest whole unit.
Page 9 Demand-Side Management 2018 Annual Report
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Supplement 1 : Cost-Effectiveness ldaho Power Company
2018 DSM Detailed Expenses by Program
Included in this supplement is a detailed breakout of program expenses as shown inAppendix 2 of the
Demand Side Management 2018 Annual Report. These expenses are broken out by funding source
major-expense type (labor/administration, materials, other expenses, purchased services, and incentives).
Table 2. 2018 DSM detailed expenses by program (dollars)
Sector/Program ldaho Rider Rider ldaho Power Tota! Program
Easy Savings: Low-lncome Energy
Efficiency Education
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Educational Distributions.
Labor/Admin istrative Expense
Materials and Equipment
Purchased Services
Energy Efficient Lighting.........
lncentives
Labor/Administrative Expense
Other Expense
Purchased Services
Energy House Calls...
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Fridge and F reezer Recycling Program...............
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services.........
Heating & Cooling Efficiency Program.................
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives
Home Energy Audit
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Multifamily Energy Savings Program
Labor/Adm in istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Oregon Residential Weatherization
Labor/Admin istrative Expense
Other Expense
lncentives
147,936
22,351
125,046
256
283
147,936
22,351
125,046
256
283
3,375,192
49,529
2,2s5,883
1,069,780
2,435,130
1,257,100
55,889
221,251
900,890
160,777
12,582
9,088
18,365
't20,742
33,907
755
1,424
(0)
31,728
585,211
116,398
6,372
71,235
83,841
307,365
264,394
57,485
21,971
50,619
134,318
205,',t3',1
64,221
38,442
37,138
65,330
5,507
3,737
957
812
3,307,782
47,054
2,207,759
1,052,970
2,343,127
1,214,018
53,094
210,614
865,401
146,7't2
11 ,954
8,634
17,491
108,634
33,172
718
1,353
(0)
31,102
565,780
110,579
6,766
69,186
80,408
298,840
264,394
57,485
21,971
50,619
134,31 I
205,1 31
64,221
38,442
37,1 38
65,330
67,409
2,475
48,124
16,81 0
92,003
43,082
2,795
10,637
35,489
14,065
628
454
874
12,108
735
37
71
0
626
19,431
5,819
(3e4)
2,048
3,432
8,525
5,507
3,737
957
812
Page 10 Demand-Side Management 2018 Annual Report
Energy Efftciency/Demand Response Total
Residential Total
$
$
27,5U,031 $
8,620,729 $
3
$
1,199,257
244,628
1,495,429 $
1,45,147 $
30,278,718
10,3't 0,503
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Oregon Rider ldaho Power Total Program
Rebate Advantage
Labor/Administrative Expense
Other Expense
Purchased Services....
lncentives
Residential New Construction Pilot Program.....
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives
Shade Tree Project
Labor/Admin istrative Expense
Materials and Equipment
4'.1,7'.l4
723
182
6,808
34,000
2
3,762
2,001
422
1,339
147,483
14,458
4,622
21,404
107,000
400,912
59,151
3,884
12,811
6,067
319,000
162,995
36,276
429
9,554
116,736
90,484
40,031
11,096
39,357
1,272,973
43,402
1,555
1,228,017
1,022,471
30,268
24,403
967,799
2
Other Expense
Purchased Services
Simple Steps, Smart Savings'".
Labor/Administrative Expense
Purchased Services
lncentives
Weatherization Assistance for Qualified Customers
Labor/Admin istrative Expense
Other Expense ...........
Purchased Services
Weatherization Solutions for Eligible Customers
Labor/Administrative Expense
Other Expense
Purchased Services
1,272,973
43,402
1,555
1,228,O17
24,237
24,237
998,233
6,031
24,403
967,799
Custom Projects
Labor/Administrative Expense
Other Expense
Purchased Services
lneentives..........
New Construction..........................
Labor/Admin istrative Expense
Other Expense...
Purchased Services
8,400,495
564,640
352,090
1 ,1 87,801
6,295,965
2,004,058
184,780
8,831
137,927
1,672,520
5,732,650
296,658
689
26,392
718,604
4,690,307
144,436
4,667
107,780
(5,1 06)
37,096
395,860
29,713
24,887
72,463
268,797
65,587
9,725
465
4,692
50,706
257,529
1 5,614
36
1,389
37,82',1
202,668
1,738
244
1,144
(26e)
618
12,156
12,067
89
8,808,s12
606,420
377,067
1,260,263
6,564,762
2,069,645
1 94,504
9,296
't42,618
1,723,226
5,990,179
312,272
725
27,781
756,425
4,892,975
146,',t74
4,911
'108,924
(5,37s)
37,714
lncentives.......
Retrofits.................
Labor/Administrative Expense
Materials and Equipment ......................
Other Expense
Purchased Services
lncentives..
Commercial Education lnitiative
Labor/Administrative Expense .
Materials and Equipment
Other Expense
Purchased Services
Page 11 Demand-Side Management 2018 Annual Report
105,770
13,735
4,439
14,596
73,000
400,910
59,15'l
3,884
'12,811
6,065
319,000
't62,995
36,276
429
9,554
116,736
86,721
38,029
10,674
38,019
Commercial/l ndustrial $$720,711 $12,156 $ 17,0i4,s09
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Rider ldaho Power Total
lrrigation Efficiency Rewards 2,681,664
336,1 29
7,917
30,1 33
4,931
2,302,554
233,916
17,685
417
1,979
171
2't3,663
38,126
38,012
2,953,706
391,826
8,334
32,226
5,103
2,516,217
Labor/Administrative Expense
Other Expense 't14
Purchased Services
lncentives
NEAA 2,375,157
2,375,157
r25,008
125,008
2,500,165
2,500,165Purchased Services
Commercial/lndustrial Energy Efficiency Overhead 444,787
307,350
157
112,461
24,819
225,437
171,075
54,362
2,926
101
300
2,525
23,0s1
16,154
8
5,583
1,306
11,865
9,004
2,861
558
409
468,396
323,913
166
118,192
26,125
237,302
180,079
57,223
2,926
101
300
2,525
1,473
632
841
172,2',t5
89,957
1,247
79,170
1,841
1,096,257
1 90,263
849,920
56,075
Labor/Admin istrative Expense
Materials and Equipment
Other Expense 149
Purchased Services
Energy Efficiency Direct Program Overhead.......
Labor/Admin istrative Expense
Other Expense
Home lmprovement
Labor/Administrative Expense
Other Expense
Purchased Services
Oregon Commercial Audit '1,473
632
841
8,961
4,498
62
4,308
92
54,125
9,467
42,001
2,657
Labor/Administrative Expense
Other Expense
Residential Energy Efficiency Education lnitiative.163,255
85,459
1 ,185
74,862
1,749
1,042,132
180,796
807,918
53,418
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Residential Energy Efficiency Overhead............
Labor/Admin istrative Expense
Other Expense
Purchased Services
Energy Efficiency Accounting and Analysis.......987,281
534,690
507
51,254
28,145
27
180,706
159,880
1,2',t9,241
722,7'15
534
20,826
475,166
17,724
6,924
10,799
98,243
98,243
Labor/Administrative Expense
Materials and Equipment
Other Expense 20,826
Purchased Services 452,O84
16,837
6,577
10,259
97,820
97,820
23,082
Energy Efficiency Advisory Group 887
347
540
424
424
Labor/Administrative Expense
Other Expense
Special Accounting Entries
Special Accounting Entry .
Page 12 Demand-Side Management 2018 Annual Report
Total $ 2,681,664 $233,916 $38,126 $ 2,953,706
Market Transformation Total I 2,175,157 $125,008 $- $ 2,500,165
Other Program and Activities Total $ 1,878,538 $99,474 $558 $ 1,978,570
lndirect Program Expensee Total
All Sectors Total
$
$
r,r01,937 $
1,'101,937 $
52,565 $
52,565 $
180,706 $
180,706 $
1,335,208
1,335,208
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Oregon Rider ldaho Power Total
A/C Cool Credit 433,659
63,912
(11 ,70e)
15,758
365,697
36,425
3,360
1
829
27,284
4,951
374,285 844,369
67,27',1
(11,708)
16,588
392,981
379,237
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives.......374,285
Flex Peak Program 58,727 64,316
3,090
61 ,227
310,270 433,313
61,816
371,496
Labor/Admin istrative Expense 58,727
lncentives.......310,270
lrrigation Peak Rewards 230,953
90,337
65,078
2,352
73,185
180,865
4,754
2,808
124
3,843
169,335
6,479,919
12,744
6,891,737
107,836
67,887
2,476
77,028
6,636,510
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives.......6,467,175
Table 3. Cost-effectiveness of 2018 programs by B/C test
Program/Sector
Educational Distributions
Energy Efficient Lighting.
TRC
4.51
6.64
1.74
0.83
3.00
1.08
't.23
0.80
4.68
0.52
0.51
RIM
0.58
0.59
0.42
o.47
0.47
0.45
0.59
0.57
0.48
0.25
0.22
PCT
N/A
13.05
N/A
1.50
N/A
2.09
1.97
N/A
8.54
N/A
N/A
Heating & Cooling Efficiency Program
Multifamily Energy Savings Program..
Rebate Advantage
Residential New Construction Pilot Program..
Shade Tree Project
Simple Steps, Smart Savings
Weatherization Assistance for Qualified Customers.................
Weatherization Solutions for Eligible Customers..
Residential Energy Efficiency Sector 2.37 3.16 0.54 10.03
Commercial Energy-Saving Kits.1.56
3.85
3.97
3.58
2.50
2.32
1.79
1.45
0.65
1 .18
0.89
0.87
N/A
1.92
1.88
1.55
Custom Projects..
New Construction
Commercial/lndustrial Energy Efficiency Sector*..............3.75 1.87 1.01 1.76
lrrigation Efficiency Rewards 4.57 3.03 1.29 2.73
lrrigation Energy Efficiency Sector*4.60 3.04 1.29 2.73
Energy Efficiency Portfolio...3.04 2.26 0.83 2.85
*Commercialilndustrial Energy Efficiency Sector costefiectiveness ratios include savings and participant costs from Green Motors Rewinds.
"*lrrigation Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Green Motors Rewinds.
Page 13 Demand-Side Management 2018 Annual Report
Demand Response Total
Residential Tota!
$
$
723,339 $
433,659 $
281,606 $
36,425 $
$
$
g,l69,4lg
844,369
7,164,475
374,285
Commercialfl ndustrial Total $58,727 $64,316 $ 310,270 $433,313
lrrigation Total s 230,953 $180,865 t 6,479,919$ 6,891,737
Grand Total $ 33,663,001 $$168 S .14,262,080
UCT
2.68
4.67
1.37
1.65
1.60
1.93
2.5',1
0.71
1.44
0.43
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