20200313DSM Annual Report Supplement 1.pdf

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DEMAN D.SIDE MANAGEMENT
Supplement 1 : Cost-Effectiveness ldaho Power Company
TaeLe oF CoNTENTS
Supplement 1 : Cost-Effectiveness
Cost-Effectiveness.....
Methodology.............
..........1
....,.....2
Assumptions .J
1
Conservation Adder .....
Net-to-Gross.................
.........5
.........6
Results..........6
2019 DSM Detailed Expenses by Program
Cost-Effectiveness Tables by Program
Educational Distributions.....
Energy Effi cient Lighting.....
Energy House Calls.........
Heating & Cooling Efficiency Program.......
Multifamily Energy Savings Program .
Rebate Advantage
Residential New Construction Pilot Program
Shade Tree Project ......
Weatherization Assistance for Qualifi ed Customers ....
Weatherization Solutions for Eligible Customers........
Commercial Energy-Saving Kits ..........
Custom Projects
New Construction .........
Retrofits
Irrigation Effi ciency Rewards
.........9
Simple Steps, Smart Savings'" ...................30
13
13
15
I7
19
22
25
27
29
JJ
.......32
.......34
.......36
.......39
.44
.......53
Page i Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Lrsr oF TABLES
Table l. 2019 non-cost-effective measures..
Table 2.2019 DSM detailed expenses by program (dollars)
Table 3. Cost-effectiveness of 2019 programs by B/C test...t2
Page ii Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
SupplEMENT 1 : Cosr-EFFEcnvENEss
Gost-Effectiveness
Idaho Power considers cost-effectiveness of primary importance in the design, implementation,
and tracking of energy efficiency and demand response programs.
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. 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 anilor throughout the country to help identiff specific
program parameters. This is accomplished through discussions with other utilities'program managers
and researchers. ldaho Power also uses electric industry research organizations, such as E Source,
Northwest Energy Efficiency Alliance (NEEA) Regional Emerging Technology Advisory Committee,
the Consortium for Energy Efficiency (CEE), American Council for an Energy-Efficient Economy
(ACEEE), andAdvanced Load Control Alliance (ALCA) 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 benefit/cost (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.ln}}2},
Idaho Power will begin using the UCT as the primary cost-effectiveness test as directed by the Idaho
Public Utilities Commission (IPUC) in Order Nos. 34469 and 34503. The company will continue to
calculate the TRC and PCT because each perspective can help inform the company and stakeholders
about the effectiveness of a particular program or measure.
Idaho Power uses 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 as
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) are distributed more broadly, and the program
cost-effectiveness increases.
When an existing progmm or measure is shown to be not cost-effective, Idaho Power works with
the Energy Efficiency Advisory Group (EEAG) to get additional input. If the measure or program
continues to be offered, the company must demonstrate 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 IPUC and Public Utility Commission of Oregon
(oPUC).
Page 1 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
In OPUC OrderNo. 94-590, issued in UM 551, the OPUC outlines specific cost-effectiveness guidelines
for energy efficiency measures and programs managed by program administrators. The OPUC expects
that measures and programs pass both the UCT and TRC tests. 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 its Oregon service area.
Non cost-effective measures and programs may be offered by a utility if they meet one or more of the
following additional conditions specified by Section l3 of OPUC 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
For operational and administrative efficiency, Idaho Power endeavors to offer identical programs in
both its Oregon and ldaho jurisdictions. Some customers, contractors, and trade allies operate in both
states. 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 Technical Assessment Guide (TAG); the California Standard Practice Manual and
its subsequent addendum; the National Action Plan for Energy Efficiency's (NAPEE) Understanding
Cost Effectiveness of Energt Efficiency Programs: Best Practices, Technical Methods, and Emerging
Issues for Policy-Makers; andthe National Action Plan on Demand Response.In the past, Idaho Power
has primarily used the TRC test for resource planning, however based on IPUC Order No. 34503,
the company will transition to using the UCT as the primary test for energy efficiency resource planning
For program planning and evaluation, the company will primarily use the UCT to develop B/C ratios to
determine the cost-effectiveness of DSM programs. The PCT provides the company the opportunity to
Page2 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
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 2019 dollars. The result of the one-year perspective is shown in Table 3 and
the Cost-Effectiveness Tables by Program section in this supplement.
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 demand-reduction capacity for the company.
As part of the public workshops on Case No. IPC-E-|3-l4,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 S16.7 million. The annual
value calculation will be updated with each Integrated Resource Plan (IRP) based on changes that
include, but are not limited to, need, capital cost, or financial assumptions. This amount was reevaluated
in the 2015,2017, and20l9 (amended) IRPs to be $18.5, $19.8, and $19.6 million, respectively.
This value is the levelized annual cost of a 17O-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. ln2019, the cost of operating the three demand response programs was
$8.3 million. Idaho Power estimates that if the three programs were dispatched for the full 60 hours,
the total costs would have been approximately $11.5 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 1:
Cost-Effectiveness, savings and costs were derived from either the Regional Technical Forum (RTF) or
the ldaho Power Energt Efficiency Potential Study conducted by Applied Energy Group (AEG).
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 RTF updates these savings and cost assumptions, Idaho Power applies them to current program
oflerings 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 in2012 dollars, measures with costs from the RTF are escalated to 2019
dollars. The costs are escalated by I l.6yo, which is the percentage provided by the RTF in workbook
RlFStandardlnformationWorkbook v4 l.xlsx.
Page 3 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Idaho Power uses a technical reference manual (TRM) developed by ADM Associates, Inc. for the
savings and cost assumptions in the Commercial and Industrial (C&I) Energy Efficiency Program's New
Construction and Retrofits options. In 2018, the company contracted with ADM to update the TRM.
Idaho Power also relies on other sources for savings and cost assumptions, such as the Northwest Power
and Conservation Council (NWPCC), 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 in the Demand-Side Management 2019 Annual Report. As a general rule, the 2019 energy
savings reported for most programs will use the assumption set at the beginning of the year.
The remaining inputs used in the cost-effectiveness models are obtained from the IRP process.
Idaho Power's 2017 IRP was acknowledged by the IPUC on February 9,2018 and by the OPUC
May 23,2018 and is the source of all the financial assumptions for the cost-effectiveness analysis.
Appendix C-Technical Appendix of Idaho Power's 2017 IRP contains the DSM alternate costs,
discount rate, and escalation rate. These DSM alternate costs vary by season and time of day and are
applied to an end-use load shape to obtain the value of a particular measure or program. The DSM
alternate 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, AURORAxmpo Electric Market Model.
The avoided capital cost of capacity is based on a gas-fired, simple-cycle turbine. In the 2017 IRP,
the annual avoided capacity cost is $I22 per kilowatt (kW).
Transmission and distribution (T&D) benefits are also included in the cost-effectiveness analyses.
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 2017 DSM alternate energy costs and included in the cost-effectiveness analysis for 2019.
Idaho Power's 2019 amended IRP was filed on January 31,2020 with the IPUC under case IPC-E-19-19
and with the OPUC under case LC 74. Because the 2019 IRP has not been acknowledged, the 2017 IRP
is the source for all financial assumptions and cost-effectiveness analysis in2019 and2020. The 2019
amended IRP is expected to be the source of all assumptions and analysis for the 2021program year.
As recommended by the NAPEE's Understanding Cost-Effectiveness of Energy Efficiency Programs,
Idaho Power's weighted average cost of capital (WACC) of 6.74% is used to discount future benefits
and costs to today's dollars. Once the DSM alternate 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
Page 4 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
can be used by the different participants. Because 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 2019 average customer segment rate and
is not escalated, the participant bill savings is discounted using arcal discount rate of 4.54%, which is
based on the 2017 IRP's WACC of 6.74Yo and an escalation rate of 2.lYo.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:
((l + 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 Demand-Side Management 2019 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 system line-loss factor is9.6Yo while the summer peak line-loss factor is9.7o/o.
Conservation Adder
T\e Pacific Northwest Electric Power Planning and Conservationlcr (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 I l0 per centum ofthe
incremental system cost of the nonconservation measure or resource.
As a result of the Northwest PowerAct, most utilities in the Pacific Northwest add a 100% conservation
adder in energy efficiency cost-effectiveness analyses. In OPUC Order No. 94-590, the OPUC states:
We support the stafls 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-12-0I, "Staffnoted that Rocky Mountain
Power and Avista use a 10% conservation adder when calculating the cost-effectiveness of all their DSM
programs." Staffrecommended the utilities have the option to use a l0o/o adder, and the IPUC agreed
with the recommendation to allow utilities to use the l0% 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,Idaho Power applies the l0o/o conservation adder in all energy
efficiency measure and program cost-effectiveness analyses when calculating the TRC test.
Page 5 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Net-to-Gross
Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE's Understanding
Cost-Effectiveness of Energt Eficiency Programs as a ratio that does the following:
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 100% for
nearly all measure and program cost-effectiveness analyses. The Home Energy Reports (HER) Pilot
Program and Shade Tree Project were two exceptions.
There is a potential of double counting savings in the HER Pilot Program if a customer receives a
report and also participates in a program such as the Energy Efficient Lighting Program. Idaho Power's
third-party consultant estimated that less than 5o/o of the savings may be double counted, so a NTG of
95% was applied to the cost-effectiveness analysis.
For the Shade Tree Project, the evaluators recommended Idaho Power use a spillover factor of 24o/o to
account for the shade the tree provides to the participant's neighboring homes. A NTG of l24o/o was
applied to the program cost-effectiveness analysis.
For the program cost-effectiveness analyses, a sensitivity analysis was also 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 UCT perspective. These NTG percentages are shown in the program cost-effectiveness pages
of Supplement I : Cost-Effectiveness.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis.
As part of Supplement l: 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-Savings
Kits, Educational Distributions, Energy House Calls, Multifamily Energy Savings Program, Shade Tree
Project, Weatherization Assistance for Qualified Customers (WAQC), and Weatherization Solutions for
Page 6 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
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 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using
actual information from 2019 and includes results of the UCI TRC, PCT, and RIM. Current 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.
In20l9, most of Idaho Power's energy efficiency programs were cost-effective from the UCT, except for
Energy House Calls and the weatheization programs for income-qualified customers.
The UCT and TRC ratios for the Energy House Calls program are 0.96 and 1.30 respectively. In late
2018 and early 2019, Idaho Power and EEAG discussed a series of topics to comply with IPUC Order
No. 34141. One part of the discussions revolved around the frequency of evaluations and the potential
effect of evaluation costs to program cost-effectiveness. EEAG recommended that cost-effectiveness be
calculated with and without the evaluation costs. Impact and process evaluations were conducted for the
Energy House Calls program in 20l9.If the evaluation costs were removed from the program's cost-
effectiveness, the UCT and TRC ratios would be 1.1I and 1.49 respectively.
WAQC had a TRC of 0.43 and a UCT ratio of 0.35, and Weatherization Solutions for Eligible Customers
had a TRC of 0.43 and a UCT ratio of 0.30. The cost-effectiveness ratios for both programs declined in
2019 from both the UCT and TRC perspective due to the adoption of the 2017 IRP DSM alternate cost
assumptions. To calculate the programs'cost-effectiveness, Idaho Power adopted the following IPUC
staffrecommendations from Case No. GNR E-12-01:
Applied a l00Yo NTG.
Claimed 100% of energy savings for each project.
Included indirect administrative overhead costs. The overhead costs of 2.459% were calculated
from the $1,194,640 of indirect program expenses divided by the total DSM expenses of
$48,584,696 as shown in Appendix 3 of the Demand-Side Management 2019 Annual Report.
Applied the llYo 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.
Fifty-two out of 285 individual measures in various programs are shown to be not cost-effective
from either the UCT or TRC perspective. Of the 52 measures, 14 are not cost-effective from the UCT
perspective. These measures will be monitored to examine their impact on the specific program's overall
cost-effectiveness. For most of the measures that fail the TRC, Idaho Power filed cost-effectiveness
a
a
o
a
o
Page 7 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
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
specified by Section 13 of Order No. 94-590. These exception requests were approved under UM-1710
or with the specific program advice filings. The filings and exception requests are noted in Table l.
Table 1 .2019 non-cost-effective measures
Program
Number of
Measures
Number
FailUCT Notes
Energy House Calls 10 10 Measures not cost-effective from UCT due to the inclusion of evaluation
costs in the administration costs. lf the evaluation cost were to be
removed, the measures and program would be cost-effective. All
measures pass the TRC.
Heating & Cooling
Efficiency Program
6 All measures except smart thermostats pass UCT. 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 thermostats requested and approved
with OPUC Advice No. '17-09.
Multifamily Energy
Savings Program
2 2 Measures have UCTs of 0.90 and TRCs between 1.40 and 1.48.
Measures not cost-effective due to the application of administration costs
on a $/kWh. Measure is included to increase savings in a cost-effective
program.
RebateAdvantage 6 0 All measures pass UCT. Measures have a TRC between 0.62 and
0.98. Three measures would be cost-effective with TRC of 1.10 without
the inclusion of administration costs. Meets OPUC Order No. 94-590,
Section 10. Measure is included to increase savings in a cost-effective
program.
Residential New
Construction Pilot
0 Measure passes UCT. Pilot program in ldaho only
New Construction
and Retrofits
7 0 All measures pass UCT. Measures offered in both options. Cost-
effectiveness exception request filed and approved with OPUC Advice
No. 18-08. OPUC Order No. 94-590, Section 13. Exceptions C and D.
New Construction 2 0 All measures pass UCT. TRC between 0.92 and 0.97. Measures are
included to increase participation a cost-effective program.
Retrofits 15 0 All measures pass UCT. TRC ranges from 0.75 to 0.99. Nine measures
would be cost-effective without the inclusion of administration costs.
Meets OPUC Order No. 94-590, Section 10. Cost-effectiveness
exception request filed and approved with OPUC Advice No. 18-08.
OPUC Order No. 94-590, Section 13 Exceptions C and D.
lrrigation Efficiency
Rewards
3 Two measures pass UCT. TRC ranges from 0.67 to 0.86. Cost-
effectiveness exception request filed with OPUC under UM-1710. OPUC
Order No. 94-590, Section 13. Approved under Order No. 18476.
Exceptions A, C, and D.
Total
Page 8
52 14
Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
In the following tables, find the annual program cost-effectiveness results that include measure-level
cost-effectiveness. Exceptions to the measure-level tables are programs that are analyzed at the project
level: the Custom Projects option of the C&I Energy Efficiency Program, the Custom Incentive Option
of Irrigation Efficiency Rewards, the Shade Tree Project, 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 non-energy impacts/benefits. 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.
2019 DSM Detailed Expenses by Program
Included in this supplement is a detailed breakout of program expenses as shown in Appendix 2 of the
Demand-Side Management 2019 Annual Report These expenses are broken out by funding source
major-expense type (labor/administration, materials, other expenses, purchased services, and incentives).
Table 2. 2019 DSM detailed expenses by program (dollars)
Sector/Program ldaho Rider Oregon Rider ldaho Power Total Program
Easy Savings: LowJncome Energy
Efficiency Education .....
Labor/Administrative Expense
Materials and Equipment
Purchased Services
Educational Distributions
Labor/Ad ministrative Expense
Materials and Equipment
Purchased Services
Energy Efficient Lighting
lncentives
Labor/Administrative Expense
Other Expense
Purchased Services
Energy House Calls.
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Heating & Cooling Efficiency Program................
lncentives.......
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Home Energy Audit
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
145,494
20,487
125,000
145,494
20,487
125,000
7
3,080,873
43,125
2,071,132
966,6't5
2,126,262
1,092,522
56,383
12,906
964,450
't6't,894
18,124
47
35,575
108,147
499,179
215,829
107,401
(2,250)
37,599
80,600
230,786
62,838
9,162
55,493
103,293
2,989,184
40,954
2,003,100
945,1 30
2,026,977
1 ,045,519
53,548
10,308
917,602
143,570
1 7,1 95
47
33,315
93,012
478,560
264,079
102,031
35,1 73
77,278
230,786
62,838
9,162
55,493
103,293
91,688
2,172
68,032
21 ,485
99,285
47,003
2,835
2,599
46,848
18,324
929
2,260
1 5,1 35
20,619
11,750
5,371
(2,250)
2,426
3,322
7
Page 9 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Oregon Rider ldaho Power Total Program
Multifamily Energy Savings Program .................
Labor/Administrative Expense
11 5,560
51,952
31 ,754
(763)
32,617
15,74s
6,067
1,474
1,870
6,335
5,982
440
3,297
1,156
1,089
8,529
6,000
921
403
1,205
131,306
58,020
33,228
1,107
38,952
5,982
440
3,297
1 ,156
1,089
156,748
109,000
18,392
8,057
21,300
534,118
431,000
59,816
92
42,953
257
147,750
38,186
365
3,772
105,427
90,499
37,873
31,879
1,359
't9,388
1,303,727
49,541
351
1,253,835
957,626
25,976
18,552
913,098
Materials and Equipment
Other Expense
Purchased Services
Oregon Residential Weatherization....................
lncentives.......
Labor/Administrative Expense
Other Expense
Purchased Services
Rebate Advantage .........................148,220
103,000
17,471
7,654
20,095
534,1't8
431,000
59,816
92
42,953
257
147,750
38,1 86
365
3,772
105,427
87,599
36,924
30,252
1,342
19,080
lncentives
Labor/Administrative Expense
Other Expense
Purchased Services
Residential New Construction Pilot Program...
lncentives
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Shade Tree Project...........
Labor/Administrative Expense .........
Materials and Equipment ......................
Other Expense
Purchased Services
Simple Steps, Smart Savings".......2,900
949
1,627
17
307
lncentives
Labor/Administrative Expense
Other Expense
Purchased Services
Ylleatherization Assistance for Qualifi ed Customers 1,303,727
49,541
351
1,253,835
20,905
20,905
Labor/Administrative Expense
Other Expense
Purchased Services
Weatherization Solutions for Eligible Customers 936,721
5,071
18,552
913,098
Labor/Administrative Expense
Other Expense
Purchased Services
Custom Projects 11,614,380
9,074,101
600,676
373,639
1,565,965
3,365,852
2,942,698
228,482
33,081
161 ,601
6,13',1,',117
5,083,828
360,1 61
212,991
115,341
31,692
7,306
58,653
182,6',14
160,018
12,087
1,741
8,769
149,939
94,354
18,982
52,501 11,879,873
9,189,442
684,869
380,9'14
1,624,618
3,548,476
3,102,716
240,568
34,822
170,370
6,281,056
5,178,182
379,143
lncentives
Labor/Administrative Expense ...52,50't
Purchased Services
New Construction
lncentives
Labor/Administrative Expense ...
Other Expense
Purchased Services
Retrofits.......
lncentives
Labor/Administrative Expense ..........
Page 10 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program Idaho Rider Oregon Rider ldaho Power TotalProgram
Materials and Equipment
Other Expense
Purchased Services
Commercial Ensrgy€aving Kits
Labor/Administrative Expense .
Materials and Equipment
Other Expense
Purchased Services
47,983
639,145
154,632
14,817
't06,555
't,702
31,559
2,525
u,077
7,3't2
785
5,201
90
1,237
50,509
673,222
161,945
15,602
111,755
1,792
32,796
lrrigation Efficiency Rewards
lncentives.......
Labor/Administrative Expense ...........................
Materials and Equipment
Other Expense
Purchased Services
2,4/,9,427
2j09,2U
299,2U
7,575
29,767
3,566
174,120
155,988
15,800
399
1,720
214
37,716
2,661,263
2,265,273
352,750
7,974
31,487
3,790
37,716
NEAA
Purchased Services
2,585,017
2,585,017
136,053
136,053
2,721,070
2,721,070
Commercial/lndustrial Energy Efiiciency Overhead
Labor/Administrative Expense
Other Expense
Purchased Services.........
Energy Efiiciency Direct Program Overhead....
Labor/Administrative Expense
Other Expense
Oregon Commercial Audit..
Labor/Administrative Expense
Other Expense
Purchased Services
Residential Energy Efftciency Education lnitiative.
Labor/Administrative Expense
Malerials and Equipment
Other Expense
Purchased Services
Residential Energy Effr ciency Overhead..............
Labor/Administrative Expense
Other Expense
Purchased Services
463,177
273,351
160,811
29,015
251,229
237,814
13,416
1s2,579
86,940
419
63,1 90
2,031
'1,293,650
187,432
1,085,308
20,910
29,758
14,897
13,334
1,527
13,390
12,529
862
7,262
620
592
6,050
8,272
4,58'l
22
3,562
't07
68,615
10,358
57,'.t22
1,135
492,935
288,218
'174,115
30,542
264,620
250,342
14,277
7,262
620
592
6,050
160,851
91,521
441
66,752
2,137
1,362,265
'197,790
1,142,430
22,045
Energy Efflciency Accounting and Analysis........
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services .........
Energy Efficiency Advisory Group
Labor/Administrative Expense
Other Expense
927,393
420,450
100
13,125
493,708
20,937
6,086
14,851
4,457
22,179
5
690
21,583
1,105
323
782
189,173
160,389
28,784
1,161,013
603,0't8
105
42,599
515,291
22,041
6,409
15,633
Page 11 Demand-Side Management 2019 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program Idaho Rider Oregon Rider ldaho Power TotalProgram
Special Accounting Entries
Special Accounting Entry
11,009
11,009
576
576
11,586
1{,586
A/C Cool Credit
lncentives
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
495,703
65,697
(18,385)
16,713
431,677
30,762
4,254
3,481
(145)
880
22,291
351,200
35 t ,200
877,665
355,456
69,'t78
(18,530)
17,593
453,968
Flex Peak Program
Labor/Administrative Expense
Other Expense
lncentives.......
75,305
72,482
2,825
256,606
252,616
3,U1
149
294,911
294,911
626,823
il7,527
76,323
2,973
lrrigation Peak Rewards
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives.......
239,523
74,140
24,470
1,384
139,530
r79,733
167,'.117
3,92't
1,288
73
7,334
6,352,452
6,350,125
2,327
6,771,708
6,517,242
80,388
25,758
1,457
146,864
Table 3. Cost-effectiveness of 2019 programs by B/C test
Program/Sector
Educational Distributions
Energy Efiicient Lighting'
Energy House Calls*
Heating & Cooling Efiiciency Program
Multifamily Energy Savings Program..
RebateAdvantage
Residential New Construction Pilot Program*
Shade Tree Project..
Simple Steps, Smart Savings
Weatherization Assistance for Qualifi ed Customers......
Weatherization Solutions for Eligible Customers..
UCT
2.06
4.04
0.96
1.56
1.15
1.82
1.58
1.09
1.40
0.35
0.30
TRC
3.32
5.17
1.30
o.77
2.34
1.14
0.83
1.16
5.56
0.43
0.43
RIM
0.49
0.52
0.34
0.43
0.39
0.39
0.45
0.52
0.43
0.21
0.18
PGT
N/A
11.72
N/A
1.48
N/A
2.55
1.55
N/A
11.10
N/A
N/A
Residential Energy Effi ciency Sector 1.90 2.29 0.46 7.76
Custom Projects*.........
Commercial Energy-Saving Kits.1.57
3.62
3.15
3.68
2.52
1.92
2.88
1.85
0.60
1.06
0.77
0.80
N/A
1.73
3.52
2.12
New Construction*
Commercial/lndustrial Energy EfEciency Sectof'3.5s 2.01 0.92 2.09
lrrigation Efiiciency Rewards 2.44 3.13 0.98 3.16
lrrigation Energy Efficiency Sectof**2.46 3.13 0.98 3.16
Energy Efhciency Portfolio 2.72 2.12 0.76 2.79
*Evaluation costs included in cost-effectiveness ratios.*'Commercial/lndustrial Energy Efiiciency Sector cost-efiectiveness ratios include savings and participant costs from Green Motors Rewinds.*'*lnigation Energy Efiiciency Sector coslefiectiveness ratios include savings and participant costs from Green Motors Rewinds.
Page 12 Demand-Side Management 2019 Annual Report
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