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ldaho Power Company Supplement 1 : Cost-Effectiveness
TeeLe or GoTTENTS
Supplement 1 : Cost-Effectiveness .....
Cost-Effectiveness
Methodology.........
Assumptions...
Conservation Adder
Net-to-Gross............
I
I
..,....2
......6
.....6
aJ
7Results......
2017 DSM Detailed Expenses by Program
Cost-Effectiveness Tables by Program .......
Educational Distributions............
Energy Effi cient Lighting....
Energy House Calls.........
Fridge and Freezer Recycling Program
Heating & Cooling Efficiency Program............
Home Improvement Program
Multifamily Energy Savings Program
Rebate Advantage....
Residential New Construction Pilot Program (ENERGY STAR@ Homes Northwest)
Simple Steps, Smart Savings'"..
Weatherization Assistance for Qualified Customers
Weatherization Solutions for Eligible Customers
Custom Projects
New Construction
Retrofits
Irrigation Effi ciency Rewards ......
..11
t6
t6
18
2t
......23
......25
......28
......30
......JJ
......35
...,.,...,,.37
............39
............40
4t
...44
...49
..58
Demand-Side Management 2017 Annual Report Page i
Supplement 1 : Cost-Effectiveness ldaho Power Company
Lrsr oF TABLES
Table I . 2017 non-cost-effective measures..............
Table 2.2017 DSM detailed expenses by program (dollars)
Thble 3. Cost-effectiveness of 2017 programs by B/C test...
..................10
1l
15
Page ii Demand-Side Management 2017 Annual Report
SuppleMENT 1 : Cosr-ErrecrvENESS
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 effrciency
and demand response opportunities are preliminarily identified through the Integrated Resource
Plan (IRP) process. Idaho Power uses third-party energy efficiency potential studies to identiff
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 identifu 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, NEEA Regional Emerging Technology
Advisory Committee, the Consortium for Energy Efficiency (CEE), American Council for an
Energy-Efficient Economy (ACEEE), Advanced Load Control Alliance (ALCA), andAssociation of
Energy Service Professionals (AESP) to compare similar programs and their results. Additionally,
Idaho Power relies on the results of program impact evaluations and recommendations from consultants.
Idaho Power's objective is for all programs to have benefit/cost (B/C) ratios greater than 1.0 for the
total resource cost (TRC) test, utility cost (UC) test, 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 it and
runs the cost-effectiveness calculations under a variety of scenarios and assumptions. 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 are 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 the 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
what 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
of Oregon (OPUC).
Demand-Side Management 2017 Annual Report Page 1
ldaho Power Company Supplement 1 : Cost-Effectiveness
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 UC 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 13 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 flles 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 its
Oregon and Idaho jurisdictions for a variety of reasons. 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 Califurnia Standard Practice Manual and
its subsequent addendum, the National Action Plan for Energy Efficiency's (NAPEE) Understanding
Page 2 Demand-Side Management 2017 Annual Report
Supplement 1 : Cost-Effectiveness ldaho Power Company
ldaho Power Company Supplement 1 : Cost-Effectiveness
Cost Effectiveness of Energt Efficiency Programs: Best Practices, Tbchnicol Methods, and Emerging
Issues for Policy-Makers; and the National Action Plan on Demand Response. For resource planning,
Idaho Power primarily uses the TRC test. This test is used because, as defined in the TAG and Califurnia
Standard Practice Manual, it is the most similar to supply-side tests, and it provides a useful basis to
compare demand-side and supply-side resources. For program planning and evaluation the company
primarily uses the TRC and the UC 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 2017 dollars. The result of the one-year perspective is shown
in Supplement l: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2017 Annual
Report includes the program cost-effectiveness to date by including the culmination of actual historic
savings values and expenses, as well as the ongoing energy-savings benefit over the life of the measures
included in a program.
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.
This $18.5 million value is the levelized annual cost of a 170-megawatt (MW) deferred resource over a
2}-year life. The demand response value calculation will include this value even in years when the IRP
shows no peak-hour capacity deficits. In20l7, the cost of operating the three demand response programs
was $8.8 million. ldaho Power estimates that if the three programs were dispatched for the full 60 hours,
the total costs would have been approximately $ 1 l. I 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 either the Regional Technical Forum (RTF)
or the ldaho Power Energt Efficiency Potential Study conducted by Applied Energy Group (AEG) in
Demand-Side Management 2017 Annual Report Page 3
Supplement 1 : Cost-Effectiveness ldaho Power Company
2014. Idaho Power received end-use load shapes from AEG which have been applied to each program
and measure when applicable. AEG refreshed the energy efficiency potential analysis in20l6. Due to
the timing of the 2016 potential study, Idaho Power will use any updated assumptions from the2016
potential study for the 2018 cost-effectiveness analyses.
The RIF regularly reviews, evaluates, and recommends eligible energy effrciency measures and the
estimated savings and costs associated with those measures. For instance, because of the rapid changes
in the lighting market, the RTF currently evaluates lighting measures annually. As the RTF 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 2006 or 2012
dollars, measures with costs from the RIF are escalated to 2017 dollars. For workbooks still in2006
dollars, the costs are escalated by 19.6 percent. For workbooks in 2012 dollars, the costs are escalated by
7.8 percent. This percentage is provided by the RTF in workbook RTFStandardlnformationWorkbook
v3 1.xlsx.
Idaho Power uses a technical reference manual (TRM) developed by ADM Associates, Inc., for the
Commercial and Industrial Energy Efficiency Program's New Construction and Retrofit options.
In20l7, the company has contracted with ADM to update the TRM in preparation for changes that will
be made to the program in 2018. Idaho Power also relies on other sources, 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 are established for the next calendar year
unless code and standard changes or program updates necessitate a need to use updated savings. As
a general rule, the 2017 energy savings reported for most programs will use the assumption set at the
beginning of the program year. These assumptions are discussed in more detail in the cost-effectiveness
sections for each 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 flnancial assumptions for the cost-effectiveness analysis.
Appendix C-Technical Appendix of Idaho Power's 2015 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 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, 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 2017 Annual Report
ldaho Power Company Supplement 1 : Cost-Effectiveness
As part of the 2015 IRP Case IPC-E-I5-19 and20l4 DSM prudence Case IPC-E-I5-06, 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 benefits, 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 was added to the 2015
DSM Alternate energy costs and included in the cost-effectiveness analysis for 2017.
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 2017 IRP was acknowledged by the IPUC on February
9,2018, in Order No. 33983. As of the publication of this report, the company has not received an
acknowledgement of the 20l7IRP from Oregon. Since the20lT IRP was acknowledged after the
budgets were set for 2018, the 2015 IRP will remain the source for all financial assumptions and
cost-effectiveness analysis in 2018. The2017IRP 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 2017 IRP,
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 Energ,,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 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 UC 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
2017 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) - (1 + Escalation)) - I : 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 2017 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. In2014,Idaho Power reviewed the system loss coefficients from 2012. Based on this study, the
line-loss factors were updated and reduced from 10.9 to 9.6 percent. The summer peak line-loss factor
was reduced from 13 to 9.7 percent.
Demand-Side Management 2017 Annual Report Page 5
Conservation Adder
The Pacific Northwest Electric Power Planning and Conservationlcl (Northwest PowerAct) states
the following:
...any conservation or resource shall not be treated as greater than that ofany
non-conservation measure or resource unless the incremental system cost of such
conservation or resource is in excess of I l0 per centum of the incremental system cost
of the nonconservation measure or resource.
As a result of the Northwest PowerAct, most utilities in the Pacific Northwest add a lO-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 107o conservation adder when calculating the cost-effectiveness of all their DSM
programs." Staffrecommended the utilities have the option to use a l0-percent adder, and the IPUC
agreed with the recommendation to allow utilities to use the l0-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,Idaho Power began applying the l0-percent conservation adder in
all energy efficiency measure and program cost-effectiveness analyses in20l4. However, on further
examination, Idaho Power observed that both Avista and Rocky Mountain Power only apply the
10-percent conservation adder when calculating the TRC test. Previously, Idaho Power had applied
the adder to the TRC test and the UC and RIM tests. Beginning in20l6,Idaho Power removed
the conservation adder from the UC and RIM tests in the program and measure cost-effectiveness
calculations.
Net-to-Gross
Net-to-gross (lt{TG), 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 effciency 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 ofthe
program. Since the NTG attempts to measure what the customers would have done in the
Supplement 1 : Cost-Effectiveness ldaho Power Company
Page 6 Demand-Side Management 2017 Annual Report
Supplement 1 : Cost-Effectiveness
absence of the energy efficiency program, it can be diffrcult 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 percent for all measure cost-effectiveness analyses. For the program cost-effectiveness analyses,
the B/C ratios shown are based on a 100-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- Effe ct iv ene 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 Educational Distributions,
Energy House Calls, Fridge and Freezer Recycling Program, Multifamily Energy Savings Program,
WeatherizationAssistance 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.
For most programs, the Demand-Side Management 2017 Annual Report Appendix 4 contains program
UC and TRC B/C ratios using actual cost information over the life of the program through 2017.
Supplement l: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using
actual information from20l7 and includes results of the PCT. 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.
The application of the 2015 DSM Alternate costs impacted the cost-effectiveness ratios for all programs
and measures within the DSM portfolio. The DSM Alternate costs declined on average 24 percent
between the2013 and2015 IRPs. However, in20l7, most of Idaho Power's energy efficiency programs
were cost-effective from the UC or TRC perspective with the exception of the Fridge and Freezer
Recycling Program, Heating & Cooling Efficiency (H&CE) Program, Home Improvement Program, and
the weathe rization programs for income -qualifi ed customers.
The Fridge and Freezer Recycling Program has a UC of 0.60 and a TRC of 1.14. The program's
cost-effectiveness has been an ongoing discussion with EEAG since 2014 due to declining deemed
savings values from the RTF and Idaho Power's DSM Alternate costs. In an attempt to lower program
administrative costs, the $30 incentive was removed in 2015 and customers were given two LED
lightbulbs for additional energy savings. When the incentives were removed, participation declined
from over 3,194 units in 2014 to 1,630 units in2015. The program faced additional challenges when
Demand-Side Management 2017 Annual Report Page 7
ldaho Power Company
Supplement 1 : CostEffectiveness ldaho Power Company
the original program vendor entered into receivership and ceased operations in late 2015.Idaho Power
temporarily suspended the program and re-launched it in June 2016 under a new name and with a new
program vendor. At that time, the OPUC authorized the program's reinstatement in Idaho Power's
Oregon service territory; however, it imposed certain specific reporting requirements. Specifically, the
OPUC requested that in 2017, the company re-evaluate the program's cost-effectiveness using the unit
energy savings based on the vintage (e.9.,"1992 and earlier" and"l993 and later") of the recycled unit
as well as the "any vintage."
When the program began in 2009, 90 percent of the freezer recycled were 1992 an older. In 2017 ,
55 percent of freezers were of that vintage. In2009,78 percent of refrigerators recycled in the
program were vintage year 1992 and older. By 2017,26 percent of the refrigerators were that vintage.
Because older units have higher savings and fewer of those units have been recycled through the
program, the program was increasingly becoming less cost-effective. In early 2077,ldaho Power
projected that if the program recycled 1,800 units, it would fail the UC and the TRC tests. The company
continued to monitor the program and by mid-summer, the program had recycled only 790 units.
It appeared the program would be on pace to only recycle 1,500 units by year end. Based on the
projected lower participation levels, the program was expected to be not be cost-effective under either
test. Other regional utilities such as Avista, Rocky Mountain Power, Energy Trust of Oregon had
recently discontinued their programs. Seattle City Light was in the process of suspending its program.
Idaho Power presented these findings at the August 2,2017, EEAG meeting. The EEAG members in
attendance supported the recommendation to end the program.
The program's higher than anticipated UC and TRC for 2017 was largely due to the large push toward
the end of the year to increase the program's participation before its discontinuation as well as a
reduction to the program's administrative costs. Due to updated savings from the RTF, the program is
still anticipated to be not cost-effective in future years.
The Heating & Cooling Efficiency Program has a UC of I .48, TRC of 0.85, PCT of 1 .47 .ln 2016,
Idaho Power reviewed the program's cost-effectiveness and notified EEAG at the August 30,2076,
meeting that the program was anticipated to be not cost-effective from the TRC perspective. Throughout
2017,Idaho Power discussed with EEAG proposed tactics it would implement to improve the program's
overall cost-effectiveness. These tactics include re-assigning non-program labor, reducing marketing
spend while improving other tactics, and reducing the stipend to participating contractors.
Idaho Power also proposed to report the cost-effectiveness of the ductless heat pumps (DHP), which are
not cost-effective, separately from the rest of the program. After reviewing the costs that were allocated
to the DHP portion of the program compared to the rest of the program, it appears that the DHP portion
of the program was assigned only 13 percent of the total administrative costs. As a result, the DHP
portion of the program had a UC of 1.87 and TRC of 0.80 while the rest of the program had a UC of
1.35 and TRC of 0.89.
Idaho Power filed changes to the program in October 2017 withthe OPUC. Effective January 1,2018,
the program has reduced the contractor stipend from $150 to $50 and added heat pump water heaters to
the measure offerings. The inclusion of the heat pump water heater measure may increase the potential
Page 8 Demand-Side Management 2017 Annual Report
ldaho Power Company Supplement 1 : Cost-Effectiveness
energy savings in the program without significantly increasing administrative costs, which may improve
the program's overall cost-effectiveness. The company plans to continue to monitor this program and
seek opportunities to improve the program's overall cost-efilectiveness.
The Home Improvement Program has a UC of 2.54, a TRC of 0.41, and a PCT of 0.70. Due to the
reduced weatherization savings from the RfF, as well as the DSM Alternate costs from the 2015 IRP,
further reduce the cost-effectiveness of the program. Idaho Power analyzed ways to modifu the program
to improve the cost-effectiveness, but despite the long 45-year life of the program and measures, the
company concluded the program would remain not cost-efi[ective. The company ended the program in
June20l7.
WAQC had a TRC of 0.48 and a UC ratio of 0.37, and Weatherization Solutions for Eligible
Customers had a TRC of 0.46 and a UC ratio of 0.34. The programs showed a decrease in savings and
cost-effectiveness ratios over 2016. The decrease to the program's overall cost-effectiveness is due in
part to the lower DSM Alternate costs from the 2015 IRP as well as the updated load shapes that reflect
most of the savings for the program occur in the non-summer months.
In20l7,Idaho Power began using the load shape for the programs' analysis that was used for electric
space heating in Idaho Power's 2015 and 2017 potential studies. The load shapes reflect the time periods
of the energy savings end uses. The load shape change reduced the value of the savings allocated to
summer months and better aligns with the electric heat nature of the program savings.
To calculate the programs'cost-efflectiveness, Idaho Power adopted the following IPUC staff's
recommendations from Case No. GNR E-12-01:
Applied a l0O-percent NTG.
Claimed 100 percent of energy savings for each project.
Included indirect administrative overhead costs. The overhead costs of 6.13 percent were
calculated from the $2,929,093 of indirect program expenses divided by the total DSM expenses
of $47 ,757,496 as shown in Appendix 3 of the Demand-Side Management 2017 Annual Report.
Applied the 10 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.
Thirty-seven out of 268 individual measures in various programs are shown to not be cost-effective from
either the UC or TRC perspective. The increase in non cost-effective measures largely due to the lower
DSM Alternate costs. These measures will be discontinued, analyzed for additional NEBs, modifled
to increase potential per-unit savings, or monitored to examine their impact on the specific program's
overall cost-effectiveness. Specifically, of the 37 non cost-effective measures, l2 have been removed
from the programs, l2have ratios between 0.90-0.99, andT have ratios between 0.80-0.89. For several
a
a
a
Demand-Side Management 2017 Annual Report Page 9
a
a
Supplement 1 : Cost-Effectiveness ldaho Power Company
measures, Idaho Power filed 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 specified by Section l3 of Order No. 94-590.
These exception requests were approved under Order No. l5-200 on June 23,2015, or with the specific
program advice filings. The filings and exception requests are noted in Table l.
Table 1 .2017 non-cost-effective measures
Program
Number of
Measures Notes
Energy Efficient
Lighting
Fridge and Freezer
Recycling Program
H&CE Program
Home lmprovement
Program
Rebate Advantage
New Construction
and Retrofits
New Construction
Retrofit
lrrigation Efficiency
Rewards Program
3 Program is cost-effective with a UC of 4.09 and TRC of 4.63. The non-cost-effective
measures were a CFL decorative and mini base bulb, a CFL globe, and a CFL reflector.
These 1 07 bulbs were carry overs from 2016 and represent 0.0061 % of overall bulbs
purchased in the program. Additionally, CFL bulbs have been removed from the Simple
Steps, Smart Savings lighting promotion.
Program was discontinued on December 31 ,2017.
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.
Air-source heat pump and duct sealing measures would be cost-effective at 1.33 and
1 .03 respectively without the inclusion of administration costs. Meets OPUC Order No,
94-590, Section 10.
Program was discontinued on June 30,2017.
ENERGY STAR and Eco-Rated manufactured homes built in Heating Zone t have a
TRC of 0.94 and 0.95 respectively. Measures would be cost-effective with TRCs of 1 .11
and 1.12 without the inclusion of administration costs. Meets OPUC Order No. 94-590,
Section 10. Program to be reviewed in 2018 with updated RTF assumptions.
Measures offered in both options. Cost-effectiveness exception request filed
and approved with OPUC Advice No. 14-06, 14-10, and 16-08. OPUC Order No.
94-590, Section 13. Exceptions C and D. Program to be reviewed in 2018 with
program updates.
Cost-effectiveness exception request filed and approved with OPUC Advice No. 14-10
and 16-08. OPUC Order No. 94-590, Section 13. Exceptions A and D. Program to be
reviewed in 2018 with program updates.
UC and TRC ranges from 0.76 to 0.99. Cost-effectiveness exception request filed and
approved with OPUC Advice No. 14-06 and 16-08. OPUC Order No. 94-590, Section
13. Exceptions C and D. Program to be reviewed in 2018 with program updates.
Measure has a UC of 3.71 and TRC of 0.92. Cost-effectiveness exception request
for rebuilt or new brass impact sprinklers filed with the OPUC under UM-1710. OPUC
Order No. 94-590, Section 13. Exception A, D, and D. Approved under Order No.
1 5-200.
4
6
5
2
4
2
10
1
Total 37
Following the annual program cost-effectiveness results are tables that include measure-level
cost-effectiveness. Exceptions to the measure-level tables are progftrms that are analyzed at the project
level. These programs include, Custom Projects, the custom option of Inigation Efficiency Rewards,
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 10 Demand-Side Management 2017 Annual Report
ldaho Power Company Supplement 1 . Cost-Effectiveness
2017 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 2017 Annual Report. These expenses are broken out by funding source
major-expense type (labor/administration, materials, other expenses, purchased services, and incentives).
Table 2. 2017 DSM detailed expenses by program (dollars)
Sector/Program ldaho Rider Oregon Rider ldaho Power Total
Easy Savings
Labor/Administrative Expense
Materials and Equipment
Other Expense
Educational Distributions.
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Energy Efficient Lighting
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Serviecs
3,323,024
41,055
2,706,267
341,442
234,260
4,787,259
61,567
1
1,073
2,082,484
2,642,',t34
170,691
15,152
2,371
15,710
137,457
259,480
18,356
6,012
27,207
207,905
575,404
't12,185
6,374
70,139
139,381
247,325
28'.t,125
59,478
20,639
71,515
129,494
165,483
51,670
237
2,393
111,183
167,342
34,556
72,324
907
141,860
2,132
129,731
9,997
84,223
3,3',t7
56
30,358
50,491
12,008
816
125
732
10,336
6,155
978
316
'1 ,1 03
3,757
18,920
6,057
335
621
5,607
6,300
149,813
24,772
125,000
40
'|.,143
1,143
1,406
1,406
2,874
2,874
1,683
1,683
1,347
1,347
149,813
24,772
1 25,000
40
3,466,027
44,330
2,835,998
351,439
234,260
4,872,888
66,291
1
1,130
2,1',t2,84'.1
2,692,626
183,035
16,30s
2,496
16,442
147,793
265,942
19,641
6,328
28,310
211,662
597,198
't2't,115
6,709
70,760
1/14,988
253,625
282,809
61,161
20,639
7'.1,515
't29,494
166,830
53,017
237
2,393
111,183
1 68,216
35,430
72,324
907
Energy House Galls.
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Fridge and Freezer Recycling Program..............
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Heating & Cooling Efficiency Program.................
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives.......
lnc€ntives.......
337
337
307
307
Home Energy Audit
Labor/Admin istrative Expense
Materials and Equipment
Other Expense
Purchased Services
Home lmprovement Program
Labor/Administrative Expense
Other Expense
Purchased Services
lncentives.......
Multifamily Energy Savings Program...................
Labor/Administrative Expense
Materials and Equipment
Other Expense
874
874
Demand-Side Management 2017 Annual Report Page 11
Energy Effi ciency/Demand Response Total
Residential Total
$
$
28,624,705 $
11,66't,597 $
1,129,736
227,882
$
$
1,574,128 $
1,497,964 $
31,328,572
13,387,443
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Oregon Rider ldaho Power Total Program
Purchased Services.........
Oregon Residential Weatherization
Labor/Administrative Expense
Other Expense
lncentives.......
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/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services .........
lncentives
Simple Steps, Smart Savings-.
Labor/Administrative Expense
Other Expense
Purchased Services
lncentives.......
Weatherization Assistance for Qualified Customerc
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services.........
Weatherization Solutions for Eligible Customers
Labor/Administrative Expense
Materials and Equipment
Other Expense
59,555
93,891
10,080
14,429
11 ,382
58,000
320,637
27,695
59
15,603
281
277,OOO
194,695
40,301
4
24,858
53,975
75,557
185,354
42,414
70
44,446
98,423
1,137,209
7,963
4,246
14,996
1 ,110,004
2,384
1,955
1't4
315
10,861
543
709
't ,610
8,000
2,232
1,494
3
721
15
5,811
2,256
4
1,315
2,236
(s6,s71)
1,122
1,122
456
456
1,307,485
40,242
4,246
7,390
1,255,607
28,224
28,224
59,555
2,384
1,955
't14
315
104,996
10,867
15,137
12,992
66,000
323,520
29,839
62
16,323
296
277,000
195,817
4',1,423
4
24,858
53,975
75,557
191,621
45,',l27
74
45,762
100,659
1,307,485
40,242
4,246
7,390
1,255,607
1,108,862
36,186
4,246
't4,996
1,053,433
0
0
244
244
650
650
Custom Projects
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
lncentives.......
New Construction.................
Labor/Administrative Expense
Other Expense
Purchased Services.........
8,352,626
539,367
3,575
308,873
1,300,586
6,200,225
2,186,213
1 98,1 95
37,257
156,893
1,793,869
4,193,475
282,373
262
311,028
29,009
188
1 5,413
60,548
20s,870
243,129
10,660
1,961
7,927
222,581
147,180
15,025
14
16,266
16,202
3,180
3,1 80
8,679,919
584,577
3,763
324,350
1 ,361,134
6,406,095
2,433,596
213,110
39,218
164,820
2,016,449
4,343,835
300,578
275
lncentives.......
Retrofits
Labor/Administrative Expense
Materials and Equipment
Page 12 Demand-Side Management 2017 Annual Report
Rebate Advantage
Commercial/lndustrial $ 14,732,314 $ 709,437 $23,701 $ 15,465,452
64
4,2il
4,254
ldaho Power Company Supplement 1 : Cost-Effectiveness
Sector/Program ldaho Rider Oregon Rider ldaho Power Total Program
Other Expense
Purchased Services
lncentives
Oregon Commercial Audits............
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services .........
50,204
735,754
3,124,883
2,642
38,547
90,952
8,102
3,848
74
880
3,300
52,847
774,300
3,215,835
8,102
3,848
74
880
3,300
lrrigation Efficiency Rewards........
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services .........
lncentives
2,230,798
309,863
1,746
72,622
4,006
1,842,561
't92,416
16,759
92
3,822
710
171 ,033
52,463
52,450
2,475,677
379,072
1,837
76,457
4,716
2,013,594
13
NEAA
Purchased Services
2,563,818
2,563,818
't34,938
134,938
2,698,756
2,698,756
CommerciaUl ndustrial Energy Efficiency Overhead
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Energy Efficiency Direct Program Overhead.......
Labor/Administrative Expense
Other Expense
Residential Energy Efficiency Education lnitiative ..
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services .........
Residential Energy Effi ciency Overhead..............
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
336,335
194,875
324
114,538
26,598
290,251
205,674
84,577
210,2',t5
84,214
1,322
131 ,544
(6,866)
1 ,001,005
164,629
209
707,200
128,967
18,472
10,986
17
6,028
't,441
17,628
1',t,127
6,501
11,152
4,560
70
6,884
(361)
50,2'.17
9,001
11
37,014
4,191
33,329
33,329
5,694
5,694
2,514
2,492
6,421
6,342
388,135
239,189
341
120,567
28,039
313,574
222,49s
91,078
223,880
91,265
1,392
138,451
(7,2281
r,057,643
179,972
220
744,293
133,158
22
79
Energy Efficiency Accounting and Analysis........
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services
Energy Efficiency Advisory Group
Labor/Administrative Expense
Other Expense
Special Accounting Entries
Speclal Accounting Entry.
878,239
510,954
52
18,935
348,299
21,685
4,537
17,147
1,833,875
1,833,875
45,728
27,662
3
1,006
17,057
1,148
245
902
(225)
(225)
148,830
125,334
23,497
1,072,797
663,950
54
43,437
365,356
22,959
4,909
18,050
1,833,651
1,833,651
Demand-Side Management 2017 Annual Report Page 13
lrrigation Total $ 2,230,798 $ 192,416 $52,463 $ 2,475,677
Market Transformation Total $ 2,563,818 $134,938 S - $ 2,698,756
Other Program and Activities Total $ 1,837,807 $97,468 $47,958 $ 1,983,232
lndirect Program Expenses Total
All Sectors Total
s
$
2,733,799 $
2,733,799 $
46,651 $
46,651 $
t48,957 s
148,957 $
2,929,407
2,929,407
126
126
Supplement 1 : Cost-Effectiveness ldaho Power Company
Sector/Program ldaho Rider Rider ldaho Power Total
A/C Cool Credit 495,142
54,783
5,231
23,192
411 ,940
(4)
39,493
2,960
275
1,221
29,791
5,245
936,272
59,268
5,506
24,412
441,731
405,353
Labor/Administrative Expense
Materials and Equipment
Other Expense
Purchased Services.........
lncentives.......400,112
Flex Peak Program 86,861
72,582
3,260
11 ,01 I
231,285
3,924
179
340,010
2,021
218
658,156
78,527
3,657
11,019
564,gs't
Labor/Administrative Expense
Other Expense
Purchased Services ..... ....
lncentives.......227,183 337,771
lrrigation Peak Rewards 743,948
63,7',t4
1 98,1 84
2,065
479,986
205,528
3,448
10,431
111
24,671
166,869
6,273,625 7,223,101
95,264
208,615
2,267
504,656
6,412,299
Labor/Administrative Expense 28,103
92
Materials and Equipment
Other Expense
Purchased Services .........
lncentives 6,245,430
Page 14 Demand-Side Management 2017 Annual Report
401,638
1,525
!rrigation Total $ 7€,948 $205,528 $ 6,273,625$ 7,223,101
Demand Resporce Total
Residential Total
t
$
1,325,951 S
495,142 $
476,305 3
39,493 $
7,015,273 s
401,638 $
8,8r7,529
936,272
Commercial/lndustrial Total $86,861 $231,285 $ 340,010 $658,156
Grand Total $$$
ldaho Power Company Supplement 1 : Cost-Effectiveness
Table 3. Cost-effectiveness of 2017 programs by B/C test
Program/Sector
Educational Distributions
Energy Efficient Lighting.
Fridge and Freezer Recycling Program
Heating & Cooling Efficiency Program .
Home lmprovement Program
Multifamily Energy Savings Program.
Rebate Advantage
Residential New Construction Pilot Program
(ENERGY STAR @ Homes Northwest)
Simple Steps, Smart Savings
Weatherization Assistance for Qualifi ed Customers.
Weatherization Solutions for Eligible Customers..
UC
3.02
4.09
1.26
0.60
1.48
2.54
1.75
1.88
TRC
6.33
4.63
1.65
1.14
0.85
0.41
3.55
1.19
RIM
0.53
0.56
0.38
0.32
o.52
0.48
0.46
0.42
PCT
N/A
7.07
N/A
N/A
1.47
0.70
N/A
2.59
2.36
2.38
0.37
0.34
1.47
5.05
0.48
0.46
0.56
0.52
o.22
0.21
2.46
6.94
N/A
N/A
Residential Energy Efficiency Sector 2.69 3.64 0.52 7.78
Custom Projects..
New Construction
Retrofits
3.53
3.90
2.92
1.95
4.64
't.'t1
1.09
0.80
0.75
1.71
6.22
1.38
Commercial/lndustrial Energy Efficiency Sectof ...............3.42 1.81 0.93 1.87
I rrigation Efficiency Rewards 4.75 3.64 1.27 3.33
lrrigation Energy Efficiency SectoP*4.78 3.65 '1.28 3.33
Energy Efficiency Portfolio.2.75 2.50 0.72 3.67
*Commercial/lndustrial Energy Efficiency Sector cost-effectiveness 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.
Demand-Side Management 2017 Annual Report Page 15
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