20170315DSM 2016 Supplement 1.pdf

2016Annual Report
MARCH 15 • 2017
DEMAND-SIDE MANAGEMENT
SUPPLEMENT 1: COST-EFFECTIVENESS
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page i
Table of ConTenTs
Supplement 1: Cost-Effectiveness ...............................................................................................................1
Cost-Effectiveness .................................................................................................................................1
Methodology ..........................................................................................................................................2
Assumptions ...........................................................................................................................................3
Conservation Adder ...............................................................................................................................5
Net-to-Gross ...........................................................................................................................................6
Results ....................................................................................................................................................6
2016 DSM Detailed Expenses by Program ...........................................................................................9
Cost-Effectiveness Tables by Program ......................................................................................................15
Easy Savings ........................................................................................................................................15
Education Distributions .......................................................................................................................17
Energy Efficient Lighting.....................................................................................................................19
Energy House Calls ..............................................................................................................................25
ENERGY STAR® Homes Northwest ...................................................................................................27
Fridge and Freezer Recycling Program (See ya later, refrigerator®) ...................................................29
Heating & Cooling Efficiency Program ...............................................................................................31
Home Improvement Program ..............................................................................................................35
Multifamily Energy Savings Program .................................................................................................37
Rebate Advantage ................................................................................................................................39
Simple Steps, Smart Savings™ .............................................................................................................43
Weatherization Assistance for Qualified Customers ............................................................................45
Weatherization Solutions for Eligible Customers ................................................................................47
New Construction (Building Efficiency) .............................................................................................49
Custom Projects (Custom Efficiency) ..................................................................................................55
Retrofits (Easy Upgrades) ....................................................................................................................59
Irrigation Efficiency Rewards ..............................................................................................................69
Supplement 1: Cost-Effectiveness Idaho Power Company
Page ii Demand-Side Management 2016 Annual Report
lisT of Tables
Table 1. 2016 non-cost-effective measures ..................................................................................................8
Table 2. 2016 DSM detailed expenses by program (dollars) .......................................................................9
Table 3. Cost-effectiveness of 2016 programs by B/C test ........................................................................13
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 1
supplemenT 1: CosT-effeCTiveness
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 cost-effectiveness analysis to assess whether a potential program design or measure will 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, 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 identify 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 (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 particular measure
or program is found to be not cost-effective from each of the three tests, Idaho Power works with the
Energy Efficiency Advisory Group (EEAG) to get input. If the measure or program is indeed offered, the
company explains why the measure or program was implemented or continued. The company believes
this aligns with the expectations of the Idaho Public Utilities Commission (IPUC) and Public Utility
Commission 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.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 2 Demand-Side Management 2016 Annual Report
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 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 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 Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging
Issues for Policy-Makers; and the National Action Plan on Demand Response. For resource planning,
Idaho Power has primarily used the TRC test and the UC test to develop B/C ratios to determine
the cost-effectiveness of DSM programs. These tests are still used because, as defined in the TAG
and California Standard Practice Manual, they are most similar to supply-side tests and provide a
useful basis to compare demand-side and supply-side resources. 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.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 3
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 2016 dollars. The result of the one-year perspective is shown
in Supplement 1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2016 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, 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.
This $16.7 million 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. 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. In 2016,
the cost of operating the three demand response programs was $9.47 million. Idaho Power estimates
that if the three programs were dispatched for the full 60 hours, the total costs would have been
approximately $12.87 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 and updated as new
information becomes available. For many of the measures within Supplement 1: Cost-Effectiveness,
savings, costs, and load shapes were derived from either the Regional Technical Forum (RTF) or the
Idaho Power Energy Efficiency Potential Study conducted by EnerNOC Utility Solutions Consulting
Group (EnerNOC) in 2012. In 2013, EnerNOC provided Idaho Power updated end-use load shapes.
Those updated load shapes have been applied to each program and measure when applicable.
Applied Energy Group (AEG) acquired EnerNOC and refreshed the energy efficiency potential
analysis in 2014 and 2016. Due to the timing of the 2016 potential study, Idaho Power used the load
shape and other measure savings assumptions from the 2012 and 2014 potential studies for the 2016
cost-effectiveness analyses.
The RTF regularly reviews, evaluates, and recommends eligible energy efficiency measures and the
estimated savings and costs associated with those measures. 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 staff participates 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,
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 4 Demand-Side Management 2016 Annual Report
measures with costs from the RTF are escalated to 2016 dollars. For workbooks still in 2006 dollars,
the costs are escalated by 14.6 percent. For workbooks in 2012 dollars, the costs are escalated by
3.3 percent. This percentage is provided by the RTF in workbook RTFStandardInformationWorkbook_
v2_6.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. 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 and goals are set 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 2016 energy savings reported for most programs will use the assumption set at the
beginning of the 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.
Since Idaho Power’s 2015 IRP was acknowledged by the IPUC and OPUC after the budgets and
goals were set for 2016, the 2013 IRP remains the source of all the financial assumptions for the
cost-effectiveness analysis. Appendix C—Technical Appendix of Idaho Power’s 2013 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 alternative 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 2013 IRP, the annual avoided capacity cost is $102 per kilowatt (kW).
As part of the 2015 IRP Case IPC-E-15-19 and 2014 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 benefits, and the analysis was presented to EEAG in
August 2016. The estimated average value of energy efficiency on T&D deferral is $3.76/kW per year or
$0.000429/kilowatt-hour (kWh). In compliance with Order No. 33365, this value was added to the 2013
DSM alternative energy costs and included in the cost-effectiveness analysis for 2016.
As recommended by the NAPEE Understanding Cost-Effectiveness of Energy Efficiency Programs¸
Idaho Power’s weighted average cost of capital (WACC) of 6.77 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 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
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 5
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 2016
average customer segment rate and is not escalated, the participant bill savings is discounted using a real
discount rate of 3.66 percent, which is based on the 2013 IRP’s WACC of 6.77 percent and an escalation
rate of 3 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)) – 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 2016 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. In 2014, 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.
Conservation 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 110 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 staff’s 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-12-01, “Staff noted that Rocky Mountain
Power and Avista use a 10% conservation adder when calculating the cost-effectiveness of all their DSM
programs.” Staff recommended the utilities have the option to use a 10-percent adder, and the IPUC
agreed with the recommendation to allow utilities to use the 10-percent adder in the cost-effectiveness
analyses for low-income programs.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 6 Demand-Side Management 2016 Annual Report
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 10-percent conservation
adder in all energy efficiency measure and program cost-effectiveness analyses in 2014. However,
upon 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. The conservation adder has now been
removed from the UC and RIM tests in the program and measure cost-effectiveness calculations
for 2016.
Net-to-Gross
Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE’s Understanding Cost
Effectiveness of Energy 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
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 pages of Supplement 1: Cost-Effectiveness.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis.
As part of Supplement 1: 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 Easy Savings, Educational
Distributions, Energy House Calls, Fridge and Freezer Recycling Program, Multifamily Energy Savings
Program, 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.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 7
For most programs, the Demand-Side Management 2016 Annual Report Appendix 4 contains program
UC and TRC B/C ratios using actual cost information over the life of the program through 2016.
Supplement 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using
actual information from 2016 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.
In 2016, most of Idaho Power’s energy efficiency programs were cost-effective, except the Fridge
and Freezer Recycling Program, Home Improvement Program, and the weatherization programs for
income-qualified customers.
The Fridge and Freezer Recycling Program has a UC of 0.92 and a TRC of 1.31. In November 2015, the
program vendor, JACO, entered receivership and ceased operations. Idaho Power then contracted with
Appliance Recycling Center of America (ARCA) and re-launched the program in June 2016. Due to the
mid-year launch, the company had forecasted that participation would be at 1,000 units, and the program
would likely not be cost-effective from the UC perspective but would be cost-effective from the TRC
perspective. This was discussed with EEAG in February 2016. When considering individual measures
within the program, both freezers and refrigerators fail the UC test with a ratio of 0.79 and 0.91,
respectively. Both freezers and refrigerators pass the TRC. However, by allowing the less cost-effective
freezers into the program, it increases overall participation and increases the program cost-effectiveness
by spreading a portion of the fixed administrative costs across more units. When Idaho Power filed
for the program to be reinstated in Oregon, the company requested a cost-effectiveness exception as
outlined in OPUC Order No. 94-590. The exception was approved by the OPUC in Advice No. 16-07.
Despite the temporary suspension of the program, 1,539 units were recycled in 2016.
The Home Improvement Program has a UC of 2.54, a TRC of 0.60, and a PCT of 0.80. The RTF
reduced savings for single-family home weatherization projects in 2015. With the changes, average
savings estimates per project for both 2015 and 2016 were just under 50 percent of 2014 projects.
These new savings were a result of the nearly 18-month RTF process to calibrate residential savings
models. Additionally, in early 2016, the RTF finished calibrating the savings models for multifamily
home weatherization projects. These new savings were approved by the RTF in March 2016 and
will be applied in 2017. These updated savings, as well as the DSM avoided costs from the 2015
IRP, further reduce the TRC and PCT of the program. Idaho Power analyzed ways to modify the
program to improve the cost-effectiveness, but the company concluded the program would remain not
cost-effective. At the August EEAG meeting, the company presented the preliminary cost-effectiveness
estimates for 2017 and shared that the Home Improvement Program would likely be cost-effective from
the UCT perspective but not from the TRC perspective. The company presented the non-cost-effective
aspects of the program at the November EEAG meeting. EEAG was shown the results of the company’s
analysis that the program would again not be cost-effective in 2016, and Idaho Power advised EEAG of
the company’s plan to end the program.
WAQC had a TRC of 0.65 and a UC ratio of 0.73, and Weatherization Solutions for Eligible Customers
had a TRC of 0.70 and a UC ratio of 0.59. The programs showed increased savings and increased
cost-effectiveness ratios over 2015. Idaho Power performed a billing analysis of the 2013 to 2014
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 8 Demand-Side Management 2016 Annual Report
weatherization projects from both WAQC and Weatherization Solutions for Eligible Customers.
The billing analysis was needed to reflect the increased replacement of forced-air electric resistance
heat systems with efficient heat pump systems. Idaho Power adopted the following IPUC staff’s
recommendations from Case No. GNR E-12-01 for calculating the programs’ cost-effectiveness:
• Applied a 100-percent NTG.
• Claimed 100 percent of energy savings for each project.
• Included indirect administrative overhead costs. The overhead costs of 5.294 percent were
calculated from the $2,263,893 of indirect program expenses divided by the total DSM
expenses of $42,763,464 as shown in Appendix 3 of the Demand-Side Management 2016
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.
Eleven individual measures in various programs are shown to not be cost-effective from either the UC
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. For several 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 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. 2016 non-cost-effective measures
Program
Number of
Measures Notes
New Construction
and Retrofits
2 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.
New Construction 1 Cost-effectiveness exception request filed and approved with OPUC Advice No. 14-10.
OPUC Order No. 94-590, Section 13. Exceptions A and D.
Energy Efficient Lighting 1 Program is cost-effective with a UC of 4.27 and TRC of 2.52. The non-cost-effective measure has a UC of 3.74 and a TRC of 0.95. These bulbs represent 1.8% of overall
bulbs in the program.
Heating & Cooling
Efficiency Program
3 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. Exceptions A and C. Approved under Order No. 15-200.
Smart thermostat currently being piloted.
Home Improvement Program 2 The program will sunset in 2017.
Fridge and Freezer
Recycling Program
2 Cost-effectiveness exception request filed with the OPUC with Advice No. 16-07. OPUC
Order No. 94-590, Section 13. Exceptions C and D. Program to be reviewed in 2017.
Total 11
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 9
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 Easy Savings, Custom Projects, the custom option of Irrigation 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.
2016 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 2016 Annual Report. These expenses are broken out by funding source
major-expense type (labor/administration, materials, other expenses, purchased services, and incentives).
Table 2. 2016 DSM detailed expenses by program (dollars)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Energy Efficiency/Demand Response
Residential
A/C Cool Credit .......................................................$ 632,079 $41,833 $429,383 $1,103,295
Labor/Administrative Expense ............................ 47,229 3,014 10,375 60,619
Materials and Equipment .................................... (47,382) 1 – (47,381)
Other Expense .................................................... 42,037 2,212 – 44,250
Purchased Services ............................................ 590,195 31,048 – 621,242
Incentives ............................................................– 5,558 419,007 424,565
Easy Savings ..........................................................–– 127,587 127,587
Labor/Administrative Expense ............................–– 2,587 2,587
Materials and Equipment ....................................–– 125,000 125,000
Education Distributions ......................................... 2,334,206 56,164 2,514 2,392,884
Labor/Administrative Expense ............................ 11,710 – 2,514 14,225
Materials and Equipment .................................... 2,051,894 53,664 – 2,105,557
Other Expense .................................................... 265,327 2,500 – 267,827
Purchased Services ............................................ 5,275 –– 5,275
Energy Efficient Lighting ....................................... 3,009,970 63,200 7,538 3,080,708
Labor/Administrative Expense ............................ 45,623 2,801 7,538 55,961
Other Expense .................................................... 42 2 – 44
Purchased Services ............................................ 869,876 19,963 – 889,839
Incentives ............................................................ 2,094,430 40,434 – 2,134,864
Energy House Calls ................................................ 188,253 15,815 2,368 206,437
Labor/Administrative Expense ............................ 15,289 929 2,368 18,587
Materials and Equipment .................................... 11,630 612 – 12,242
Other Expense .................................................... 16,625 809 – 17,434
Purchased Services ............................................ 144,709 13,465 – 158,174
ENERGY STAR® Homes Northwest ....................... 138,203 1,510 2,445 142,158
Labor/Administrative Expense ............................ 14,326 882 2,445 17,654
Materials and Equipment .................................... 474 25 – 499
Other Expense .................................................... 13,235 594 – 13,828
Purchased Services ............................................ 167 9 – 176
Incentives ............................................................ 110,000 –– 110,000
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 10 Demand-Side Management 2016 Annual Report
Table 2. 2016 DSM detailed expenses by program (dollars) (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Fridge and Freezer Recycling Program................$ 250,535 $ 4,555 $ 2,826 $ 257,916
Labor/Administrative Expense ............................ 20,549 1,234 2,826 24,610
Materials and Equipment .................................... 12,042 634 – 12,675
Other Expense .................................................... 27,008 1,173 – 28,181
Purchased Services ............................................ 190,937 1,513 – 192,450
Heating & Cooling Efficiency Program ................. 545,454 27,184 22,275 594,913
Labor/Administrative Expense ............................ 113,453 7,143 22,275 142,871
Materials and Equipment .................................... 2,934 154 – 3,089
Other Expense .................................................... 28,561 1,390 – 29,951
Purchased Services ............................................ 181,056 8,771 – 189,827
Incentives ............................................................ 219,450 9,725 – 229,175
Home Energy Audit ................................................ 278,959 – 10,853 289,812
Labor/Administrative Expense ............................ 52,990 – 10,853 63,843
Materials and Equipment .................................... 33,851 – – 33,851
Other Expense .................................................... 66,688 – – 66,688
Purchased Services ............................................ 125,431 – – 125,431
Home Improvement Program ................................ 309,799 – 14,225 324,024
Labor/Administrative Expense ............................ 71,564 – 14,225 85,789
Other Expense .................................................... 85,646 – – 85,646
Purchased Services ............................................ 7,424 – – 7,424
Incentives ............................................................ 145,166 – – 145,166
Multifamily Energy Savings Program ................... 55,758 – 3,288 59,046
Labor/Administrative Expense ............................ 15,314 – 3,288 18,603
Materials and Equipment .................................... 22,482 – – 22,482
Other Expense .................................................... 815 – – 815
Purchased Services ............................................ 17,147 – – 17,147
Oregon Residential Weatherization ...................... – 3,906 24 3,930
Labor/Administrative Expense ............................ – 2,635 24 2,660
Other Expense .................................................... – 844 – 844
Incentives ............................................................ – 426 – 426
Rebate Advantage .................................................. 103,056 6,392 1,602 111,050
Labor/Administrative Expense ............................ 10,159 619 1,602 12,380
Other Expense .................................................... 18,477 972 – 19,449
Purchased Services ............................................ 74,420 4,801 – 79,221
Shade Tree Project ................................................. 70,669 – 5,973 76,642
Labor/Administrative Expense ............................ 20,256 – 5,973 26,229
Other Expense .................................................... 16,158 – – 16,158
Purchased Services ............................................ 34,255 – – 34,255
Simple Steps, Smart Savings™ .............................. 147,055 3,535 3,194 153,784
Labor/Administrative Expense ............................ 36,631 2,095 3,194 41,920
Other Expense .................................................... 40 2 – 42
Purchased Services ............................................ 50,411 570 – 50,981
Incentives ............................................................ 59,973 868 – 60,841
Weatherization Assistance for Qualified Customers – – 1,289,809 1,289,809
Labor/Administrative Expense ............................ – – 48,208 48,208
Materials and Equipment .................................... – – 18 18
Other Expense .................................................... – – 2,304 2,304
Purchased Services ............................................ – – 1,239,279 1,239,279
Weatherization Solutions for Eligible Customers 1,226,540 56,571 40,681 1,323,793
Labor/Administrative Expense ............................ 6,470 – 40,681 47,151
Materials and Equipment .................................... 7,019 – – 7,019
Other Expense .................................................... 16,212 – – 16,212
Purchased Services ............................................ 1,196,840 56,571 – 1,253,411
Residential Total .....................................................$ 9,290,536 $280,664 $1,966,587 $11,537,787
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 11
Table 2. 2016 DSM detailed expenses by program (dollars) (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Commercial/Industrial
New Construction (Building Efficiency) ...............$ 1,863,584 $ 42,559 $ 25,079 $ 1,931,222
Labor/Administrative Expense ............................ 150,397 9,243 25,079 184,719
Other Expense .................................................... 33,022 1,738 – 34,760
Purchased Services ............................................ 186,606 8,976 – 195,582
Incentives ............................................................ 1,493,559 22,602 – 1,516,161
Custom Projects (Custom Efficiency) .................. 7,664,563 237,146 80,916 7,982,624
Labor/Administrative Expense ............................ 477,233 29,296 80,916 587,445
Other Expense .................................................... 248,405 6,471 – 254,876
Purchased Services ............................................ 964,847 61,212 – 1,026,060
Incentives ............................................................ 5,974,077 140,167 – 6,114,243
Retrofits (Easy Upgrades) ..................................... 4,791,852 228,834 19,505 5,040,190
Labor/Administrative Expense ............................ 282,547 15,896 19,505 317,947
Other Expense .................................................... 43,750 2,303 – 46,053
Purchased Services ............................................ 749,147 39,082 – 788,228
Incentives ............................................................ 3,716,409 171,553 – 3,887,962
Flex Peak Program ................................................. 105,116 247,897 414,984 767,997
Labor/Administrative Expense ............................ 77,438 4,951 16,862 99,251
Materials and Equipment .................................... 65 3 – 68
Other Expense .................................................... 23,091 1,215 – 24,307
Purchased Services ............................................ 4,522 238 – 4,760
Incentives ............................................................ – 241,489 398,122 639,611
Oregon Commercial Audits ................................... – 7,717 – 7,717
Labor/Administrative Expense ............................ – 2,693 – 2,693
Other Expense .................................................... – 74 – 74
Purchased Services ............................................– 4,950 – 4,950
Commercial/Industrial Total ..................................$ 14,425,115 $764,152 $540,483 $15,729,750
Irrigation
Irrigation Efficiency Rewards ................................ 1,672,328 634,101 65,923 2,372,352
Labor/Administrative Expense ............................ 206,096 13,175 65,923 285,194
Materials and Equipment .................................... 5,930 310 – 6,239
Other Expense .................................................... 64,813 3,411 – 68,225
Purchased Services ............................................ 5,296 87 – 5,383
Incentives ............................................................ 1,390,193 617,118 – 2,007,311
Irrigation Peak Rewards 1,082,113 218,906 6,299,056 7,600,076
Labor/Administrative Expense ............................ 36,699 2,350 56,766 95,814
Materials and Equipment .................................... 128,886 4,268 – 133,154
Other Expense .................................................... 23,266 1,225 – 24,490
Purchased Services ............................................ 893,263 47,014 – 940,277
Incentives ............................................................– 164,050 6,242,290 6,406,340
Irrigation Total .........................................................$2,754,442 $853,008 $6,364,979 $9,972,428
Energy Efficiency/Demand Response Total $ 26,470,093 $1,897,824 $8,872,049 $37,239,965
Market Transformation
NEAA ....................................................................... 2,542,567 133,820 – 2,676,387
Purchased Services ............................................ 2,542,567 133,820 – 2,676,387
Market Transformation Total .................................$2,542,567 $133,820 $– $2,676,387
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 12 Demand-Side Management 2016 Annual Report
Table 2. 2016 DSM detailed expenses by program (dollars) (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Other Programs and Activities
Residential Education Initiative ................................$ 259,301 $ 12,071 $ 18,806 $ 290,179
Labor/Administrative Expense ............................ 87,585 5,597 18,806 111,989
Materials and Equipment .................................... 1,540 81 – 1,621
Other Expense .................................................... 165,572 6,151 – 171,722
Purchased Services ............................................ 4,604 242 – 4,846
Energy Efficiency Direct Program Overhead ....... 238,767 16,965 37,307 293,039
Labor/Administrative Expense ............................ 173,750 11,109 37,307 222,166
Other Expense .................................................... 65,017 5,856 – 70,873
Other Programs and Activities Total $498,068 $29,036 $56,114 $583,218
Indirect Program Expenses
Commercial/Industrial Energy Efficiency Overhead ............................................... 222,704 16,653 86,715 326,072
Labor/Administrative Expense ............................ 70,119 8,149 86,715 164,983
Materials and Equipment .................................... 329 14 – 343
Other Expense .................................................... 130,708 6,833 – 137,541
Purchased Services ............................................ 21,548 1,658 – 23,205
Energy Efficiency Accounting and Analysis ........ 848,975 49,358 251,197 1,149,530
Labor/Administrative Expense ............................ 405,270 25,906 247,240 678,416
Materials and Equipment .................................... 560 29 – 590
Other Expense .................................................... 46,761 2,470 3,957 53,189
Purchased Services ............................................ 396,383 20,952 – 417,336
Energy Efficiency Advisory Group 14,365 806 954 16,125
Labor/Administrative Expense ............................ 4,443 284 954 5,681
Other Expense .................................................... 9,921 522 – 10,444
Residential Energy Efficiency Overhead.............. 783,384 44,818 35,987 864,189
Labor/Administrative Expense ............................ 97,406 7,014 35,987 140,407
Materials and Equipment .................................... 4 0 – 4
Other Expense .................................................... 661,490 35,992 – 697,482
Purchased Services ............................................ 24,484 1,812 – 26,296
Special Accounting Entries ................................... (88,576) (3,447)– (92,024)
Special Accounting Entry .................................... (88,576) (3,447) – (92,024)
Indirect Program Expenses Total ..........................$1,780,851 $108,187 $374,854 $2,263,893
Grand Total $31,291,579 $2,168,868 $9,303,017 $42,763,464
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 13
Table 3. Cost-effectiveness of 2016 programs by B/C test
Program/Sector UC TRC RIM PCT
Easy Savings .............................................................................. 1.69 2.04 0.55 N/A
Education Distributions ............................................................... 3.63 6.33 0.65 N/A
Energy Efficient Lighting ............................................................. 4.27 2.52 0.68 3.17
Energy House Calls .................................................................... 2.11 2.75 0.56 N/A
ENERGY STAR® Homes Northwest ........................................... 1.79 1.00 0.63 1.46
Fridge and Freezer Recycling Program...................................... 0.92 1.31 0.43 N/A
Heating & Cooling Efficiency Program ....................................... 2.33 1.26 0.71 1.76
Home Improvement Program ..................................................... 2.54 0.60 0.64 0.80
Multifamily Energy Savings Program.......................................... 1.43 2.55 0.51 N/A
Rebate Advantage ...................................................................... 3.89 3.33 0.62 6.45
Simple Steps, Smart Savings ..................................................... 2.40 1.33 0.61 2.13
Weatherization Assistance for Qualified Customers ................... 0.73 0.65 0.41 N/A
Weatherization Solutions for Eligible Customers ........................ 0.59 0.70 0.36 N/A
Residential Energy Efficiency Sector ..................................... 2.74 2.36 0.63 4.10
Custom Projects .........................................................................5.26 2.86 1.44 1.92
New Construction .......................................................................4.40 3.07 0.96 3.19
Retrofits ...................................................................................... 3.83 2.64 0.93 2.83
Commercial/Industrial Energy Efficiency Sector* ................. 4.67 2.81 1.19 2.31
Irrigation Efficiency Rewards ...................................................... 4.95 3.21 1.34 2.78
Irrigation Energy Efficiency Sector** ...................................... 5.00 3.17 1.35 2.73
Energy Efficiency Portfolio...................................................... 3.58 2.56 0.95 2.93
*Commercial/Industrial Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Green Motors Rewinds.**Irrigation Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Green Motors Rewinds.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 14 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 15
CosT-effeCTiveness Tables by program
Easy Savings
Segment: Residential
2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ...................................................$ 215,005 $127,587 1.69
TRC Test .................................................260,217 127,587 2.04
RIM Test ..................................................215,005 392,804 0.55
PCT ......................................................... N/A N/A N/A
Cost Inputs Ref
Program Administration ..........................................................................$127,587
Program Incentives.................................................................................–I
Total UC .................................................................................................$127,587 P
Measure Equipment and Installation (Incremental Participant Cost)......$–M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................402,961
NPV Cumulative Energy (kWh) ........................................3,191,271 $215,005 S
10% Credit (Northwest Power Act)...................................21,501
Total Electric Savings .........................................................$236,506 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$ 265,217 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$–NUI
NEBs ................................................................................$23,712 NEB
Benefits and Costs Included in Each Test
UC Test ................................................= S * NTG = P
TRC Test ..............................................= (A + NUI + NEB) * NTG = P
RIM Test ..............................................= S * NTG = P + (B * NTG)
PCT .....................................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................59%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: NEBs include the present value (PV) of periodic bulb (capital) replacement costs. No participant cost.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 16 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 17
Education Distributions
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test .............................................$8,696,521 $2,392,884 3.63
TRC Test ...........................................15,158,067 2,392,884 6.33
RIM Test ............................................8,696,521 13,285,551 0.65
PCT .................................................. N/A N/A N/A
Cost Inputs Ref
Program Administration ..........................................................................$ 2,392,884
Program Incentives.................................................................................–I
Total UC .................................................................................................$ 2,392,884 P
Measure Equipment and Installation (Incremental Participant Cost)......$–M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)..........................15,149,605
NPV Cumulative Energy (kWh) ..............................129,492,498 $8,696,521 S
10% Credit (Northwest Power Act).........................869,652
Total Electric Savings ...............................................$9,566,173 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ...............$ 10,892,667 B
Other Benefits
Non-Utility Rebates/Incentives ................................$–NUI
NEBs .......................................................................$5,591,894 NEB
Benefits and Costs Included in Each Test
UC Test ................................................= S * NTG = P
TRC Test ..............................................= (A + NUI + NEB) * NTG = P
RIM Test ..............................................= S * NTG = P + (B * NTG)
PCT .....................................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................28%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: Energy savings as reported by the Resource Action Plan for the 2015 to 2016 student kits.
NEBs for giveaway bulbs, student kit bulbs, and energy-savings kits include PV of periodic bulb (capital) replacement costs. NEBs for student kit and energy-savings kit showerheads include the NPV of water and wastewater savings.
No participant cost.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 18 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
General Purpose LED
Give away
Efficient Technology: LED
Lamp Type: General purpose and dimmable Lumen Category: 665 to 1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 13 9.00 $6.50 $3.95 – – $0.158 4.57 7.81 1
Drying Rack Drying rack 25% of clothes
dryer use
Rack ENRes_SF_Dryer 5 85.48 $26.90 – – – $0.158 1.99 2.19 2
Student Energy
Efficiency Kit (SEEK) Program
2015–2016 kit offering. Kits include: high-
efficiency showerhead, shower timer, 3 LEDs, FilterTone alarm, digital thermometer, LED nightlight.
No kit Kit IPC_Student Kits 11 244.51 $152.77 $11.86 – – $0.158 3.96 4.66 3
Energy-
Savings Kit
Three 250–664-lumen
general purpose bulbs Six 665–1439-lumen
general purpose bulbs One 1.75-gallons per minute (gpm) high-
efficiency showerheads (electric kit only)
Three faucet aerators (electric kit only)
No kit Kit IPC_Energy-savings
Kits
11 384.20 $240.22 $133.86 – – $0.158 3.96 6.56 4
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest
Power Act.d No participant cost.e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.2 Idaho Power calculations based on data from the NEEA’s 2011 Residential Building Stock Assessment and RTF’s clothes washer workbook.3 Resource Action Programs. 2015–2016 Idaho Power Energy Wise Program Summary Report. 2016.
4 Lightbulbs—RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. Showerhead - RTF. ResShowerheads_v2_1.xlsm. 2011. Faucet aerators—AEG. Potential Study.
Year: 2016 Program: Education Distributions Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 19
Energy Efficient Lighting
Segment: Residential2016 Program Results
Cost Inputs Ref
Program Administration ..........................................................................$945,844
Program Incentives.................................................................................2,134,864 I
Total UC .................................................................................................$3,080,708 P
Measure Equipment and Installation (Incremental Participant Cost)$9,821,995 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)........................21,093,813
NPV Cumulative Energy (kWh) ............................192,709,405 $13,153,997 S
10% Credit (Northwest Power Act).......................1,315,400
Total Electric Savings .............................................$14,469,397 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .............$16,404,560 B
Other Benefits
Non-Utility Rebates/Incentives ..............................$–NUI
NEBs .....................................................................$12,642,707 NEB
Benefits and Costs Included in Each Test
UC Test ................................................= S * NTG = P
TRC Test ..............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ..............................................= S * NTG = P + (B * NTG)
PCT .....................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................23%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Note: NEBs include PV of periodic bulb (capital) replacement costs.
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ...................................................$13,153,997 $3,080,708 4.27
TRC Test .................................................27,112,104 10,767,839 2.52
RIM Test ..................................................13,153,997 19,485,267 0.68
PCT .........................................................31,182,131 9,821,995 3.17
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 20 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Decorative and Mini-base
CFL Retailer
Efficient Technology: Compact fluorescent
Lamp Type: Decorative and mini-base Lumen Category: 250 to 664 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 9 9.00 $4.67 $9.57 $1.63 $1.05 $0.045 3.21 7.23 1
Decorative
and Mini-base CFL
Retailer
Efficient Technology:
Compact fluorescent Lamp Type: Decorative and
mini-base Lumen Category: 665 to 1,439 lumens
Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 9 16.00 $8.31 $13.76 $0.06 $1.42 $0.045 3.88 29.36 1
Decorative and Mini-base
CFL Retailer
Efficient Technology: Compact fluorescent
Lamp Type: Decorative and mini-base Lumen Category: 1,440 to 2,600 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 9 20.00 $10.39 – $0.39 $2.00 $0.045 3.58 8.86 1
General
Purpose CFL Retailer
Efficient Technology:
Compact fluorescent Lamp Type: General
purpose and dimmable Lumen Category: 250 to 664 lumens
Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 9 8.00 $4.15 $10.13 $0.06 $0.50 $0.045 4.83 35.00 1
General Purpose CFL
Retailer
Efficient Technology: Compact fluorescent
Lamp Type: General purpose and dimmable Lumen Category: 665 to 1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 9 8.00 $4.15 $2.82 $0.06 $0.50 $0.045 4.83 17.59 1
General
Purpose CFL Retailer
Efficient Technology:
Compact fluorescent Lamp Type: General
purpose and dimmable Lumen Category: 1,440 to 2,600 lumens
Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 8 14.00 $6.50 $2.76 $0.06 $0.51 $0.045 5.70 14.37 1
Globe CFL Retailer Efficient Technology: Compact fluorescent
Lamp Type: Globe Lumen Category: 250 to 664 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 6.00 $4.04 $10.63 $0.06 $0.60 $0.045 4.64 45.68 1
Year: 2016 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 21
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use Measure Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Globe CFL Retailer Efficient Technology: Compact fluorescent Lamp Type: Globe Lumen Category: 665 to
1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 8.00 $5.39 $16.62 $0.06 $1.00 $0.045 3.96 53.68 1
Reflectors and
Outdoor CFL Retailer
Efficient Technology:
Compact fluorescent Lamp Type: Reflectors and outdoor
Lumen Category: 250 to 664 lumens
Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 8 11.00 $5.11 $23.30 $0.06 $1.23 $0.045 2.96 52.11 1
Reflectors and Outdoor CFL Retailer
Efficient Technology: Compact fluorescent Lamp Type: Reflectors and outdoor Lumen Category: 665 to
1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 7 18.00 $7.34 $21.07 $0.06 $2.06 $0.045 2.56 33.50 1
Reflectors and
Outdoor CFL Retailer
Efficient Technology:
Compact fluorescent Lamp Type: Reflectors and outdoor
Lumen Category: 1,440 to 2,600 lumens
Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 5 46.00 $13.39 $37.43 $2.29 $2.00 $0.045 3.29 11.96 1
Three-Way CFL Retailer
Efficient Technology: Compact fluorescent Lamp Type: Three-way Lumen Category: 1,440 to 2,600 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 8 33.00 $15.33 $29.61 $6.09 $2.00 $0.045 4.40 6.13 1
Decorative and Mini-base
LED Retailer
Efficient Technology: LED Lamp Type: Decorative and
mini-base Lumen Category: 250 to 664 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 13.00 $8.75 $10.57 $8.41 $2.00 $0.045 3.39 2.25 1
General Purpose LED
Retailer
Efficient Technology: LED Lamp Type: General
purpose and dimmable Lumen Category: 250 to 664 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 10.00 $6.73 $11.21 $2.50 $1.49 $0.045 3.47 6.31 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 22 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use Measure Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
General Purpose LED
Retailer
Efficient Technology: LED Lamp Type: General
purpose and dimmable Lumen Category: 665 to 1,439 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 11.00 $7.41 $4.00 $7.04 $1.41 $0.045 3.89 1.61 1
General Purpose LED
Retailer
Efficient Technology: LED Lamp Type: General
purpose and dimmable Lumen Category: 1,440 to
2,600 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 22.00 $14.81 $3.92 $20.34 $2.97 $0.045 3.74 0.95 1, 2
Globe LED Retailer Efficient Technology: LED Lamp Type: Globe
Lumen Category: 250 to 664 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 8.00 $5.39 $10.63 $4.31 $1.02 $0.045 3.90 3.55 1
Globe LED Retailer Efficient Technology: LED Lamp Type: Globe
Lumen Category: 665 to 1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 12.00 $8.08 $16.62 $3.75 $2.01 $0.045 3.17 5.95 1
Reflectors and
Outdoor LED Retailer
Efficient Technology: LED
Lamp Type: Reflectors and outdoor
Lumen Category: 250 to 664 lumens Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 12 16.00 $10.77 $26.09 $16.57 $1.95 $0.045 4.04 2.19 1
Reflectors and Outdoor LED Retailer
Efficient Technology: LED Lamp Type: Reflectors and outdoor
Lumen Category: 665 to 1,439 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 27.00 $18.18 $21.03 $11.62 $2.91 $0.045 4.41 3.20 1
Reflectors and Outdoor LED Retailer
Efficient Technology: LED Lamp Type: Reflectors and outdoor
Lumen Category: 1,440 to 2,600 lumens
Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 60.00 $40.40 $44.01 $25.77 $3.00 $0.045 7.09 3.11 1
Three-Way LED
Retailer
Efficient Technology: LED Lamp Type: Three-way
Lumen Category: 665 to 1,439 lumens Space Type: Any
Baseline bulb Lamp ENRes_SF_Lighting 12 27.00 $18.18 – $11.29 $3.00 $0.045 4.31 1.60 3
Three-Way
LED Retailer
Efficient Technology: LED
Lamp Type: Three-way Lumen Category: 1,440 to
2,600 lumens Space Type: Any
Baseline
bulb
Lamp ENRes_SF_Lighting 12 60.00 $40.40 – $16.39 $2.87 $0.045 7.25 2.33 3
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 23
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use Measure Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
CFL Fixture Retailer CFL fixture Baseline bulb Fixture ENRes_SF_Lighting 15 98.29 $80.22 – $20.90 $8.00 $0.045 6.46 3.48 3
LED Indoor Fixture Retailer
LED fixture retailer Baseline bulb Fixture ENRes_SF_Lighting 18 28.54 $27.81 $2.58 $6.65 $3.93 $0.045 5.33 4.18 3, 4
LED Outdoor Fixture Retailer
LED fixture—outdoor retailer Baseline bulb Fixture IPC_Outdoor Lighting 12 63.55 $32.02 $6.48 $22.13 $6.06 $0.045 3.59 1.67 3, 4
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))1 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.
2 Measure not cost-effective. Will monitor in 2017.
3 BPA. UES_Measures_List_4_1_20151021.xlsx. 2015.
4 Weighted average of savings for BPA LED fixtures based on 2016 sales.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 24 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 25
Energy House Calls
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ...................................................$ 435,705 $206,437 2.11
TRC Test .................................................567,279 206,437 2.75
RIM Test ..................................................435,705 784,828 0.56
PCT ......................................................... N/A N/A N/A
Cost Inputs Ref
Program Administration ..........................................................................$206,437
Program Incentives.................................................................................–I
Total UC .................................................................................................$206,437 P
Measure Equipment and Installation (Incremental Participant Cost)......$–M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................509,859
NPV Cumulative Energy (kWh) ........................................6,287,232 $435,705 S
10% Credit (Northwest Power Act)...................................43,571
Total Electric Savings .........................................................$ 479,276 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$578,391 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$–NUI
NEBs ................................................................................$88,003 NEB
Benefits and Costs Included in Each Test
UC Test .............................................= S * NTG = P
TRC Test ...........................................= (A + NUI + NEB) * NTG = P
RIM Test ...........................................= S * NTG = P + (B * NTG)
PCT ..................................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................47%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: NEBs include PV of periodic bulb (capital) replacement costs for direct install LED bulbs. NEBs for showerheads include the NPV of water and wastewater savings.
No participant cost.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 26 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
PTCS Duct Sealing Manufactured Home Prescriptive Duct Sealing—
Electric Forced Air Furnace (FAF)—Heating Zone 1
Pre-existing duct leakage Home ENRes_MH_Heater 18 973.00 $761.80 ––– $0.405 1.93 2.13 1
PTCS Duct
Sealing
Manufactured Home
Prescriptive Duct Sealing—Electric FAF—Heating Zone 2 or 3
Pre-existing
duct leakage
Home ENRes_MH_Heater 18 1,248.00 $977.10 ––– $0.405 1.93 2.13 1
PTCS Duct Sealing Manufactured Home Prescriptive Duct Sealing—Heat Pump—Heating Zone 1
Pre-existing duct leakage Home ENRes_MH_Heater 18 615.00 $481.51 ––– $0.405 1.93 2.13 1
PTCS Duct
Sealing
Manufactured Home
Prescriptive Duct Sealing—Heat Pump—Heating Zone
2 or 3
Pre-existing
duct leakage
Home ENRes_MH_Heater 18 876.00 $685.85 ––– $0.405 1.93 2.13 1
General Purpose LED Direct Install
Efficient Technology: LED Lamp Type: General purpose and dimmable Lumen Category: 665 to 1,439 lumens
Space Type: ANY
Baseline bulb Lamp ENRes_SF_Lighting 12 18.00 $12.12 $17.57 –– $0.405 1.66 4.24 2
Low-Flow Faucet Aerator 1.0–1.5 gpm kitchen or bathroom faucet aerator Non-low-flow faucet
aerator
Aerator ENRes_SF_WtrHtr 10 106.00 $60.88 ––– $0.405 1.42 1.56 3
Water Heater Pipe Covers Up to 6 feet No existing coverage Pipe wrap ENRes_SF_WtrHtr 15 150.00 $122.83 ––– $0.405 2.02 2.22 3
Low-Flow
Showerheads
Residential Showerhead
Replacement_2_00gpm_Any Shower_ Electric Water Heating_Direct Install
Any
showerhead 2.2 gpm or higher
Showerhead ENRes_SF_WtrHtr 10 139.00 $79.83 $110.12 –– $0.405 1.42 3.52 4
Low-Flow Showerheads Residential Showerhead Replacement_1_75gpm_Any Shower_ Electric Water
Heating_Direct Install
Any showerhead 2.2 gpm or
higher
Showerhead ENRes_SF_WtrHtr 10 222.00 $127.50 $172.11 –– $0.405 1.42 3.47 4
a Average measure life.b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d No participant cost.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResHeatingCoolingDuctSealingMH_v2_0.xlsm. 2015.
2 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.
3 AEG. Potential Study.4 RTF. ResShowerheads_v2_1.xlsm. 2011.
Year: 2016 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 27
ENERGY STAR® Homes Northwest
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test .................................................$254,666 $142,158 1.79
TRC Test ...............................................296,775 297,518 1.00
RIM Test ................................................254,666 401,901 0.63
PCT .......................................................386,386 265,360 1.46
Cost Inputs Ref
Program Administration ..........................................................................$32,158
Program Incentives.................................................................................110,000 I
Total UC .................................................................................................$142,158 P
Measure Equipment and Installation (Incremental Participant Cost)......$265,360 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...............................150,282
NPV Cumulative Energy (kWh) ...................................2,424,906 $254,666
10% Credit (Northwest Power Act)..............................25,467
Total Electric Savings ....................................................$280,133 S
Participant Bill Savings
NPV Cumulative Participant Savings ..........................$259,743 B
Other Benefits
Non-Utility Rebates/Incentives ....................................$–NUI
NEBs ...........................................................................$16,643 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................100%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: 2009 International Energy Conservation Code (IECC) adopted in Idaho in 2011. Oregon Residential Specialty Code adopted in Oregon in 2011.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 28 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
ENERGY
STAR home
Multifamily—Heat
Pump—Heating Zone 1 Cooling Zone 3
Multi-family home
built to IECC 2009 Code. Adopted 2011.
Home Prog_Energy
Star Homes NW
36 1,294.00 $2,192.80 $154.10 $2,286.27 $1,000.00 $0.214 1.72 1.00 1
Next Step Home Next Step Home Single family home built to IECC 2009
Code. Adopted 2011.
Home IPC_Residential 36 5,265.00 $10,761.23 – $9,087.00 $1,000.00 $0.214 5.06 1.16 2
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResNewSFEStarOR_v3_0.xlsm. 2014.
2 NEEA Next Step Home.
Year: 2016 Program: ENERGY STAR Homes Northwest Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 29
Fridge and Freezer Recycling Program (See ya later, refrigerator®)
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test .................................................$236,992 $257,916 0.92
TRC Test ...............................................336,682 257,916 1.31
RIM Test ................................................236,992 549,967 0.43
PCT ....................................................... N/A N/A N/A
Cost Inputs Ref
Program Administration ..........................................................................$257,916
Program Incentives................................................................................. –I
Total UC .................................................................................................$257,916 P
Measure Equipment and Installation (Incremental Participant Cost)......$ –M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...............................632,186
NPV Cumulative Energy (kWh) ...................................3,646,797 $236,992 S
10% Credit (Northwest Power Act)..............................23,699
Total Electric Savings ....................................................$260,691 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ....................$292,051 B
Other Benefits
Non-Utility Rebates/Incentives ....................................$ –NUI
NEBs ...........................................................................$75,991 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................N/A = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................109%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: Program re-launched on June 1, 2016. No participant cost.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 30 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Freezer
Recycling
Freezer removal and
decommissioning
–Freezer ENRes_SF_
Freezer
5 570.00 $182.67 $50.86 –– $0.408 0.79 1.08 1, 2
Refrigerator Recycling Refrigerator removal and decommissioning –Refrigerator ENRes_SF_SecRef 6 356.00 $132.67 $41.42 –– $0.408 0.91 1.29 1, 2
General
Purpose LED Give away
Give away_LED_General
Purpose, Dimmable, and Three-Way_250 to 1,049 lumens
Baseline bulb Lamp ENRes_SF_
Lighting
13 9.00 $6.50 $3.95 –– $0.408 1.77 3.02 3
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d No participant cost.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))1 RTF. ResFridgeFreezeDecommissioning_v3_1.xlsm. 2014.
2 Measure not cost-effective. Will monitor in 2017.
3 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.
Year: 2016 Program: Fridge and Freezer Recycling Program Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 31
Heating & Cooling Efficiency Program
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ...................................................$1,387,634 $594,913 2.33
TRC Test .................................................1,767,557 1,404,625 1.26
RIM Test ..................................................1,387,634 1,954,477 0.71
PCT .........................................................1,829,900 1,038,887 1.76
Cost Inputs Ref
Program Administration ...........................................................................$365,738
Program Incentives..................................................................................229,175 I
Total UC ..................................................................................................$594,913 P
Measure Equipment and Installation (Incremental Participant Cost).......$1,038,887 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...............................1,113,574
NPV Cumulative Energy (kWh) ...................................14,484,058 $1,387,634 S
10% Credit (Northwest Power Act)..............................138,763
Total Electric Savings ....................................................$1,526,397 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ....................$1,359,564 B
Other Benefits
Non-Utility Rebates/Incentives .....................................$–NUI
NEBs ............................................................................$241,161 NEB
Benefits and Costs Included in Each Test
UC Test .............................................= S * NTG = P
TRC Test ...........................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ...........................................= S * NTG = P + (B * NTG)
PCT ..................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................62%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Note: NEBs include NPV of RTF values for annual operation and maintenance (O&M) savings and monetized comfort savings.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 32 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Heat Pump (HP)
Conversion
Existing single family and manufactured home
heating, ventilation, and air conditioning (HVAC) conversion to heat pump with commissioning and sizing (Heating & Cooling
Zone Weighted Average)
Conversion to high-
efficiency heat pump
Unit ENRes_SF_HeatPump 15 5,457.00 $5,261.52 $993.00 $3,981.00 $800.00 $0.328 2.03 1.17 1, 2, 3, 4
Heat Pump Upgrade Existing single family and manufactured home
HVAC heat pump upgrade (Heating & Cooling Zone Weighted Average)
Heat pump to heat pump
upgrade
Unit ENRes_SF_HeatPump 15 881.00 $849.44 $92.00 $240.00 $250.00 $0.328 1.58 1.94 1, 2, 3, 4
Heat Pump Upgrade New construction single family and manufactured home HVAC heat pump
upgrade (Heating & Cooling Zone Weighted Average)
Heat pump to heat pump upgrade
Unit ENRes_SF_HeatPump 15 948.00 $914.04 $85.00 $240.00 $250.00 $0.328 1.63 1.98 1, 2, 3, 4
Open Loop HP Open loop water source
heat pump for existing homes—14.00 EER 3.5 COP (Heating & Cooling
Zone Weighted Average)
Electric
resistance/oil propane
Unit ENRes_SF_HeatPump 20 9,610.00 $11,973.85 – $7,660.00 $1,000.00 $0.328 2.88 1.22 5
Open Loop HP Open loop water source heat pump for new
construction—14.00 EER 3.5 COP (Heating & Cooling Zone Weighted Average)
Electric resistance/
oil propane
Unit ENRes_SF_HeatPump 20 8,481.00 $10,567.14 – $11,951.00 $1,000.00 $0.328 2.79 0.79 5, 6
Open Loop HP Open loop water source heat pump—14.00 EE 3.5 COP (Heating & Cooling
Zone Weighted Average)
Heat pump Unit ENRes_SF_HeatPump 20 9,095.00 $11,332.17 – $3,816.00 $500.00 $0.328 3.25 1.83 5
Ductless Heat Pump Zonal to DHP. (Heating & Cooling Zone Weighted
Average)
Zonal electric Unit ENRes_SF_HeatPump 15 2,334.00 $2,250.39 $1,020.00 $3,220.00 $750.00 $0.328 1.48 0.88 1, 6
Evaporative Cooler Evaporative cooler Central air conditioning
(A/C)
Unit ENRes_SF_CAC 12 457.00 $644.33 –– $150.00 $0.328 2.15 2.36 7
Prescriptive Duct Sealing Duct tightness—PTCS duct sealing—average heating system. Weighted average of Heating Zones 1–3.
Pre-existing duct leakage Unit ENRes_SF_Heater 20 1,095.00 $960.24 – $612.00 $350.00 $0.328 1.35 1.09 8
Electronically Commutated
Motor (ECM) Blower Motor
ECM blower motor Permanent split capacitor
(PSC) motor
Unit ENRes_SF_HVAC 18 515.00 $586.79 – $300.00 $50.00 $0.328 2.68 1.38 9
Year: 2016 Program: Heating & Cooling Efficiency Program Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 33
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Whole House Fan Whole house fan Displaced forced air dx cooling
Unit ENRes_SF_CAC 18 446.00 $865.92 – $700.00 $200.00 $0.328 2.50 1.13 7
Smart Thermostat Smart thermostat –Unit ENRes_SF_Heater 10 758.00 $344.27 – $303.96 $75.00 $0.328 1.06 0.69 10, 11
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))1 RTF. ResSFExistingHVAC_v4_1.xlsx. Weighted average of 2016 participants in heating and cooling zones 1–3.
2 RTF. ResHeatingCoolingCommissioningControlsSizingSF_v3_6.xlsm. Weighted average of 2016 participants in heating and cooling zones 1–3.
3 RTF. ResMHExistingHVAC_v3_3.xlsx. Weighted average of 2016 participants in heating and cooling zones 1–3.
4 RTF. ResMHHeatingCoolingCommissioningControlsSizing_v3_3.xlsx. Weighted average of 2016 participants in heating and cooling zones 1–3.5 RTF. ResGSHP_v2_6. 2016. Median 2014–2016 participant costs. Weighted average of 2016 participants in heating and cooling zones 1–3.6 Measure not cost-effective.
7 AEG. Potential Study.
8 RTF. ResSFPerformanceBasedDuctSealing_v3_2.xlsm.
9 Idaho Power engineering calculations based on Integrated Design Lab inputs. 2015.10 RTF. ResConnectedTstats_v1.1.xlsm11 Measure not cost-effective. Measure is being piloted and will be monitored in 2017.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 34 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 35
Home Improvement Program
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$821,746 $324,024 2.54
TRC Test ..................................................1,011,503 1,685,301 0.60
RIM Test ...................................................821,746 1,278,959 0.64
PCT ..........................................................1,207,683 1,506,443 0.80
Cost Inputs Ref
Program Administration ...........................................................................$178,858
Program Incentives..................................................................................145,166 I
Total UC ..................................................................................................$324,024 P
Measure Equipment and Installation (Incremental Participant Cost).......$1,506,443 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)................................500,280
NPV Cumulative Energy (kWh) ....................................8,448,495 $821,746 S
10% Credit (Northwest Power Act)...............................82,175
Total Electric Savings .....................................................$903,920 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .....................$954,935 B
Other Benefits
Non-Utility Rebates/Incentives .....................................$–NUI
NEBs ............................................................................$107,582 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................N/A
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: NEBs include NPV of RTF values for annual wood fuel savings. Unable to perform minimum NTG sensitivity analysis. Program fails the TRC test regardless of the NTG percentage.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 36 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Multi Family—Floor
Insulation
Greater than R38. Electric heat. Program
weighted average.
Attic Insulation R20 or less Square Feet ENRes_MF_Heater 45 0.73 $1.13 – $0.72 $0.15 $0.358 2.75 1.27 1
Multi Family—Attic Insulation Greater than R30 or fill floor cavity. Electric
heat. Program weighted average.
Floor Insulation R5 or less Square Feet ENRes_MF_Heater 45 2.20 $3.41 –$1.18 $0.50 $0.358 2.65 1.91 1
Multi Family—Windows U-Factor of 0.30 or lower. Electric heat. Program weighted average.
Single pane metal, Single pane wood or double pane metal.
Square Feet ENRes_MF_Heater 45 17.60 $27.26 – $20.55 $2.50 $0.358 3.10 1.12 1, 2
Single
Family—Attic Insulation
Greater than R38.
Electric heat. Program weighted average.
Attic Insulation
R20 or less
Square
Feet
ENRes_SF_Heater 45 0.44 $0.69 $0.14 $0.84 $0.15 $0.358 2.22 0.90 3, 4
Single
Family—Floor Insulation
Greater than R30 or
fill floor cavity. Electric heat. Program weighted average.
Floor Insulation
R5 or less
Square
Feet
ENRes_SF_Heater 45 0.84 $1.29 $0.27 $1.12 $0.50 $0.358 1.62 1.19 3
Single Family—Wall Insulation
Greater than R11 or fill wall cavity. Electric heat. Program weighted
average.
Wall Insulation R5 or less Square Feet ENRes_SF_Heater 45 1.29 $2.00 $0.41 $1.84 $0.50 $0.358 2.08 1.14 3
Single Family—
Window
U-Factor of 0.30 or lower. Electric heat.
Program weighted average.
Single pane metal, Single pane wood
or double pane metal.
Square Feet ENRes_SF_Heater 45 7.72 $11.96 $2.84 $40.22 $2.50 $0.358 2.27 0.37 3, 4, 5
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest
Power Act.d Based on average 2016 customer costs.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. Weighted average of savings by heating and cooling zone, heating and cooling system, and insulation level or U-Factor. ResWXMF_v2_2.xls. 2011.2 RTF. Incremental costs from ResWxMF_v2_2.xls. 2011.
3 RTF. Weighted average of savings by heating and cooling zone, heating and cooling system, and insulation level or U-Factor. ResWXSF_v3_4.xls. 2015.
4 Measure not cost-effective.
5 RTF. Incremental costs from ResWxSF_v3_4.xls. 2015.
Year: 2016 Program: Home Improvement Program Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 37
Multifamily Energy Savings Program
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$84,438 $59,046 1.43
TRC Test ..................................................150,761 59,046 2.55
RIM Test ...................................................84,438 166,725 0.51
PCT ..........................................................N/A N/A N/A
Cost Inputs Ref
Program Administration ...........................................................................$59,046
Program Incentives.................................................................................. –I
Total UC ..................................................................................................$59,046 P
Measure Equipment and Installation (Incremental Participant Cost).......$ –M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................149,760
NPV Cumulative Energy (kWh) ........................................1,280,081 $84,438 S
10% Credit (Northwest Power Act)...................................8,444
Total Electric Savings .........................................................$92,882 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$107,678 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$ –NUI
NEBs ................................................................................$57,879 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................70%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 38 Demand-Side Management 2016 Annual Report
Year: 2016 Program: Multifamily Energy Savings Program Market Segment: Residential Program Type: Energy Efficiency
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
General Purpose LED
Retailer
Efficient Technology: LED Lamp Type: General
purpose and dimmable Lumen Category: 665 to
1,439 lumens Space Type: ANY
Baseline bulb Lamp ENRes_SF_Lighting 12 11.00 $7.41 $4.00 –– $0.394 1.71 2.80 1, 2
General Purpose LED
Direct Install
Efficient Technology: LED Lamp Type: General
purpose and dimmable Lumen Category: 665 to
1,439 lumens Space Type: ANY
Baseline bulb Lamp ENRes_SF_Lighting 12 18.00 $12.12 $17.57 –– $0.394 1.71 4.36 1
Reflector LED
Direct Install
Efficient Technology: LED
Lamp Type: Reflectors and outdoor Lumen Category: 665 to
1,439 lumens Space Type: Moderate and
High-use Interior
Baseline bulb Lamp ENRes_SF_
Lighting
12 32.00 $21.55 $64.27 –– $0.394 1.71 6.98 1
Globe LED Direct Install Efficient Technology: LED Lamp Type: Globe Lumen Category: 250 to
664 lumens Space Type: Moderate and
high-use interior
Baseline bulb Lamp ENRes_SF_Lighting 12 12.00 $8.08 $16.87 –– $0.394 1.71 5.45 1
Low-Flow Showerheads
Direct Install
Residential Showerhead Replacement_2_00gpm_
Any Shower_ Electric Water Heating_Direct Install
Any showerhead
2.2 gpm or higher
Showerhead ENRes_SF_WtrHtr 10 139.00 $79.83 $110.12 –– $0.394 1.46 3.61 3
Water Heater Pipe Covers Up to 6 feet No existing coverage Pipe wrap ENRes_SF_WtrHtr 15 150.00 $122.83 ––– $0.394 2.08 2.29 4
Low-Flow Faucet Aerator 1.0–1.5 gpm kitchen or bathroom faucet aerator Non-low-flow faucet aerator Aerator ENRes_SF_WtrHtr 10 106.00 $60.88 ––– $0.394 1.46 1.60 4
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d No participant cost.e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.
2 Used the retail savings assumptions for the Pocatello LED installations due to the replacement of some CFLs. RTF direct install savings assume the replacement of incandescent and halogens. RTF retail savings assume the replacement of incandescent, halogens, and CFLs.
3 RTF. ResShowerheads_v2_1.xlsm. 2011.
4 AEG. Potential Study.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 39
Rebate Advantage
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$432,209 $111,050 3.89
TRC Test ..................................................493,456 148,142 3.33
RIM Test ...................................................432,209 691,673 0.62
PCT ..........................................................664,649 103,092 6.45
Cost Inputs Ref
Program Administration ...........................................................................$45,050
Program Incentives..................................................................................66,000 I
Total UC ..................................................................................................$111,050 P
Measure Equipment and Installation (Incremental Participant Cost).......$103,092 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................411,272
NPV Cumulative Energy (kWh) ........................................5,902,930 $432,209 S
10% Credit (Northwest Power Act)...................................43,221
Total Electric Savings .........................................................$475,430 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$580,623 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$–NUI
NEBs ................................................................................$18,026 NEB
Benefits and Costs Included in Each Test
UC Test ...............................................= S * NTG = P
TRC Test .............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test .............................................= S * NTG = P + (B * NTG)
PCT ....................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................26%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 40 Demand-Side Management 2016 Annual Report
Year: 2016 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency
Benefit Cost B/C Tests
Measure
Name
Measure
Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e
UC
Ratiof
TRC
Ratiog Source
ENERGY STAR®
manufactured home
New Energy Star Manufactured Home
with Electric FAF—Heating Zone 1
Manufactured home built to Housing and
Urban Development (HUD) code
Home ENRes_MH_Heater 26 5,420.00 $5,873.50 $270.44 $1,577.57 $1,000.00 $0.110 3.68 3.10 1
ENERGY
STAR manufactured home
New Energy Star
Manufactured Home with Electric FAF—Heating Zone 2
Manufactured home
built to HUD code
Home ENRes_MH_Heater 27 6,847.00 $7,638.07 $276.61 $1,577.57 $1,000.00 $0.110 4.36 3.72 1
ENERGY STAR manufactured
home
New Energy Star Manufactured Home with Electric FAF—
Heating Zone 3
Manufactured home built to HUD code Home ENRes_MH_Heater 27 8,057.00 $8,987.87 $276.61 $1,577.57 $1,000.00 $0.110 4.76 4.12 1
ENERGY STAR
manufactured home
New Energy Star Manufactured Home
with Heat Pump—Heating Zone 1 Cooling Zone 3
Manufactured home built to HUD code Home ENRes_SF_HeatPump 23 3,254.00 $4,525.55 $250.52 $1,577.57 $1,000.00 $0.110 3.33 2.70 1
ENERGY STAR manufactured
home
New Energy Star Manufactured Home with Heat Pump—
Heating Zone 2 Cooling Zone 1
Manufactured home built to HUD code Home ENRes_SF_HeatPump 25 4,346.00 $6,424.51 $264.04 $1,577.57 $1,000.00 $0.110 4.35 3.57 1
ENERGY
STAR manufactured home
New Energy Star
Manufactured Home with Heat Pump—Heating Zone 2
Cooling Zone 2
Manufactured home
built to HUD code
Home ENRes_SF_
HeatPump
25 4,390.00 $6,489.55 $264.04 $1,577.57 $1,000.00 $0.110 4.38 3.59 1
ENERGY STAR
manufactured home
New Energy Star Manufactured Home
with Heat Pump—Heating Zone 2 Cooling Zone 3
Manufactured home built to HUD code Home ENRes_SF_HeatPump 25 4,472.00 $6,610.77 $264.04 $1,577.57 $1,000.00 $0.110 4.43 3.64 1
ENERGY STAR manufactured
home
New Energy Star Manufactured Home with Heat Pump—
Heating Zone 3 Cooling Zone 1
Manufactured home built to HUD code Home ENRes_SF_HeatPump 26 5,516.00 $8,381.93 $270.44 $1,577.57 $1,000.00 $0.110 5.22 4.34 1
ENERGY
STAR manufactured home
New EcoRated
Manufactured Home with Electric FAF—Heating Zone 1
Manufactured home
built to HUD code
Home ENRes_SF_
HeatPump
26 5,691.00 $8,647.85 $270.44 $1,993.00 $1,000.00 $0.110 5.32 3.74 1
ENERGY STAR manufactured
home
New EcoRated Manufactured Home with Electric FAF—
Heating Zone 2
Manufactured home built to HUD code Home ENRes_SF_HeatPump 27 7,438.00 $11,598.01 $276.61 $1,993.00 $1,000.00 $0.110 6.38 4.64 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 41
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. NewMH_EStar_EcoRated_v1_3.xls. 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 42 Demand-Side Management 2016 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 43
Simple Steps, Smart Savings™
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$368,523 $153,784 2.40
TRC Test ..................................................506,754 379,752 1.33
RIM Test ...................................................368,523 602,763 0.61
PCT ..........................................................611,199 286,809 2.13
Cost Inputs Ref
Program Administration ...........................................................................$ 92,943
Program Incentives..................................................................................60,841 I
Total UC ..................................................................................................$153,784 P
Measure Equipment and Installation (Incremental Participant Cost).......$286,809 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................577,320
NPV Cumulative Energy (kWh) ........................................5,274,322 $368,523 S
10% Credit (Northwest Power Act)...................................36,852
Total Electric Savings .........................................................$405,375 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$448,979 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$ –NUI
NEBs ................................................................................$101,379 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................55%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Note: NEBs include the NPV of water savings from low-flow showerheads and clothes washers.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 44 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Clothes Washer ENERGY STAR® clothes washer—Any Baseline clothes
washers
Clothes washer ENRes_SF_Washer 14 67.00 $56.65 $12.49 $61.47 $10.23 $0.161 2.70 1.04 1, 2
Low-Flow Showerhead Low-flow showerhead 2.0 gpm
Any shower any water Heating Retail
Showerhead 2.2 gpm or
higher
Showerhead ENRes_SF_WtrHtr 10 66.78 $38.35 $104.86 $27.50 $7.00 $0.161 2.16 3.84 3
Low-Flow Showerhead Low-flow showerhead 1.75 gpm Any shower any water
Heating Retail
Showerhead 2.2 gpm or higher
Showerhead ENRes_SF_WtrHtr 10 99.77 $57.30 $153.83 $27.50 $7.00 $0.161 2.48 4.98 3
Low-Flow
Showerhead
Low-flow showerhead
1.5 gpm Any shower any water Heating
Retail
Showerhead
2.2 gpm or higher
Showerhead ENRes_SF_WtrHtr 10 129.12 $74.16 $195.54 $27.50 $7.00 $0.161 2.67 5.74 3
a Average measure life.b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 BPA. UES_Measures_List_4_1_20151021.xlsx. 2015.
2 NEBs and participant costs from RTF. Based on the CEE tiers and the weighted average of sales. ResClothesWashersSF_v5_2.xlsm. 2015.3 RTF. ResShowerheads_v2_1.xlsm. 2011. Adjusted savings by changing Electric Water Heating saturation from 64% to 52% to match IPC mix.
Year: 2016 Program: Simple Steps, Smart Savings Market Segment: Residential Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 45
Weatherization Assistance for Qualified Customers
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$994,297 $1,358,091 0.73
TRC Test ..................................................1,306,729 2,002,697 0.65
RIM Test ...................................................994,297 2,411,503 0.41
PCT ..........................................................N/A N/A N/A
Cost Inputs Ref
Program Administration ...........................................................................$181,711
Community Action Partnership (CAP) Agency Payments........................ 1,108,098
Total UC ..................................................................................................$1,289,809 P
Idaho Power Indirect Overhead Expense Allocation—5.294%................$68,282 OH
Additional State Funding .........................................................................644,606 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...............................746,162
NPV Cumulative Energy (kWh) ...................................10,709,122 $994,297 S
10% Credit (Northwest Power Act)..............................99,430
Total Electric Savings ....................................................$1,093,726 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ....................$1,053,412 B
Other Benefits
Non-Utility Rebates/Incentives ....................................$–NUI
NEBs ...........................................................................
Health and Safety ..................................................$185,571
Repair ....................................................................$27,432
Other ......................................................................–
NEBs Total ..................................................................$213,003 NEB
Benefits and Costs Included in Each Test
UC Test ...........................................= S * NTG = P + OH
TRC Test .........................................= (A + NUI + NEB) * NTG = P + OH + M
RIM Test .........................................= S * NTG = P + OH + (B * NTG)
PCT ................................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................153%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: Savings from the billing analysis of the 2013–2014 weatherization projects. Program cost-effectiveness incorporated IPUC staff recommendations from case GNR-E-12-01. Recommendations include: Claimed 100% of savings; increased NTG to 100%; added a 10% conservation
preference adder; health, safety, and repair NEBs; and allocation of indirect overhead expenses. No customer participant costs. Costs shown are from the DOE state weatherization assistance program.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 46 Demand-Side Management 2016 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 47
Weatherization Solutions for Eligible Customers
Segment: Residential2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ....................................................$828,382 $1,393,874 0.59
TRC Test ..................................................970,438 1,393,874 0.70
RIM Test ...................................................828,382 2,271,507 0.36
PCT ..........................................................N/A N/A N/A
Cost Inputs Ref
Program Administration ...........................................................................$262,940
Weatherization LLC Payments ................................................................ 1,060,853
Total UC ..................................................................................................$1,323,793 P
Idaho Power Indirect Overhead Expense Allocation—5.294%................$70,082 OH
Additional State Funding .........................................................................–M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)....................................621,653
NPV Cumulative Energy (kWh) ........................................8,922,127 $828,382 S
10% Credit (Northwest Power Act)...................................82,838
Total Electric Savings .........................................................$911,220 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings .........................$877,633 B
Other Benefits
Non-Utility Rebates/Incentives .........................................$–NUI
NEBs ................................................................................
Health and Safety .......................................................47,109
Repair .........................................................................12,109
Other ...........................................................................–
NEBs Total .......................................................................$59,218 NEB
Benefits and Costs Included in Each Test
UC Test ..........................................= S * NTG = P +OH
TRC Test ........................................= (A + NUI + NEB) * NTG = P + OH + M
RIM Test ........................................= S * NTG = P + OH + (B * NTG)
PCT ...............................................N/A N/A
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................168%
Average Customer Segment Rate/kWh ..............................................................$0.086
Line Losses .........................................................................................................9.60%
Notes: Savings from the billing analysis of the 2013–2014 weatherization projects. Program cost-effectiveness incorporated IPUC staff recommendations from case GNR-E-12-01. Recommendations include: Claimed 100% of savings; increased NTG to 100%; added a 10% conservation
preference adder; health, safety, and repair NEBs; and allocation of indirect overhead expenses. No customer participant costs.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 48 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 49
New Construction (Building Efficiency)
Segment: Commercial2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ................................................$8,500,742 $1,931,222 4.40
TRC Test ..............................................9,350,816 3,044,665 3.07
RIM Test ...............................................8,500,742 8,812,392 0.96
PCT ......................................................8,397,331 2,629,604 3.19
Cost Inputs Ref
Program Administration ...........................................................................$415,061
Program Incentives..................................................................................1,516,161 I
Total UC ..................................................................................................$1,931,222 P
Measure Equipment and Installation (Incremental Participant Cost).......$2,629,604 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...........................12,393,249
NPV Cumulative Energy (kWh) ...............................120,039,923 $8,500,742 S
10% Credit (Northwest Power Act)..........................850,074
Total Electric Savings ................................................$9,350,816 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ................$6,881,170 B
Other Benefits
Non-Utility Rebates/Incentives ................................$–NUI
NEBs .......................................................................$–NEB
Benefits and Costs Included in Each Test
UC Test .............................................= S * NTG = P
TRC Test ...........................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ...........................................= S * NTG = P + (B * NTG)
PCT ..................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................23%
Average Customer Segment Rate/kWh ..............................................................$0.057
Line Losses .........................................................................................................9.60%
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 50 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e
UC
Ratiof
TRC
Ratiog Source
Lighting Interior light load reduction. Part A: 10–19.9% below
code.
Code standards sq ft ENComm_InsLt 14 0.51 $0.44 – $0.26 $0.10 $0.039 3.63 1.71 1
Lighting Interior light load reduction. Part B: 20–29.9% below
code.
Code standards sq ft ENComm_InsLt 14 1.03 $0.88 – $0.51 $0.20 $0.039 3.66 1.76 1
Lighting Interior light load reduction. Part C: Equal to or greater than 30% below code.
Code standards sq ft ENComm_InsLt 14 2.33 $1.99 – $0.89 $0.30 $0.039 5.09 2.23 1
Lighting Exterior light load reduction. Minimum of 15% below code.Code standards kW IPC_Outdoor Lighting 15 4,059.00 $2,494.63 – $168.00 $200.00 $0.039 6.96 8.41 1
Lighting Daylight photo controls Code standards sq ft ENComm_InsLt 14 0.94 $0.80 – $0.91 $0.25 $0.039 2.80 0.93 1, 2
Lighting Occupancy sensors Code standards Sensor ENComm_InsLt 8 366.00 $190.08 – $38.26 $25.00 $0.039 4.84 3.98 1
Lighting High-efficiency exit signs Code standards Sign IPC_8760 16 28.00 $24.67 – $10.83 $7.50 $0.039 2.87 2.28 1
A/C IECC 2009 >5–11 ton A/C unit that meets CEE Tier 1 >11–19 ton A/C unit that
meets CEE Tier 1 >19–25 ton A/C unit that
meets CEE Tier 1 (≥65,000 British thermal units/hour [Btu/hr] &
≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 40.30 $46.50 – $36.18 $30.00 $0.039 1.47 1.36 3
A/C IECC 2012 >5–11 ton A/C unit that meets CEE Tier 1
>11–19 ton A/C unit that meets CEE Tier 1 >19–25 ton A/C unit that
meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000
Btu/hr)
Code standards Tons ENComm_Cooling 15 96.30 $111.12 – $81.57 $30.00 $0.039 3.29 1.43 3
A/C IECC 2009 & 2012 ≤5 ton A/C unit that meets CEE Tier 2
>5–11 ton A/C unit that meets CEE Tier 2 >11–19 ton A/C unit that
meets CEE Tier 2 >19–25 ton A/C unit that
meets CEE Tier 2 (≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 90.16 $104.04 – $115.37 $75.00 $0.039 1.33 0.96 2, 4, 5
Year: 2016 Program: New Construction Market Segment: Commercial Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 51
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e
UC Ratiof
TRC Ratiog Source
A/C IECC 2009 ≤5 ton HP unit that meets CEE Tier 1 >5–11 ton HP unit that meets CEE Tier 1
>11–19 ton HP unit that meets CEE Tier 1 >19–25 ton HP unit that meets CEE Tier 1 (≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 27.25 $31.44 – $31.83 $30.00 $0.039 1.01 1.05 4
A/C IECC 2012 ≤5 ton HP unit that meets
CEE Tier 1 >5–11 ton HP unit that meets
CEE Tier 1 >11–19 ton HP unit that meets CEE Tier 1
>19–25 ton HP unit that meets CEE Tier 1
(≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 45.18 $52.13 – $28.03 $30.00 $0.039 1.64 1.93 4
A/C IECC 2009 >5–11 ton A/C VRF unit that meets CEE Tier 1 >11–19 ton A/C VRF unit that meets CEE Tier 1 >19–25 ton A/C VRF unit that
meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 132.60 $153.01 – $115.37 $75.00 $0.039 1.91 1.40 3
A/C IECC 2012 >5–11 ton A/C VRF unit that meets CEE Tier 1 >11–19 ton A/C VRF unit that
meets CEE Tier 1 >19–25 ton A/C VRF unit that
meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 188.51 $217.53 – $161.54 $75.00 $0.039 2.64 1.42 3
A/C IECC 2009 >5–11 ton HP VRF unit that meets CEE Tier 1 >11–19 ton HP VRF unit that
meets CEE Tier 1 >19–25 ton HP VRF unit that meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 138.52 $159.84 – $97.36 $75.00 $0.039 1.99 1.71 3
A/C IECC 2012 >5–11 ton HP VRF unit that
meets CEE Tier 1 >11–19 ton HP VRF unit that
meets CEE Tier 1 >19–25 ton HP VRF unit that meets CEE Tier 1
(≥65,000 Btu/hr & ≤300,000 Btu/hr)
Code standards Tons ENComm_Cooling 15 56.80 $65.54 – $91.88 $75.00 $0.039 0.85 0.77 2, 3, 5
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 52 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e
UC Ratiof
TRC Ratiog Source
A/C Air-cooled chiller condenser, IPLV 14.0 EER or higher Code standards Tons ENComm_Cooling 20 472.44 $696.03 – $86.12 $80.00 $0.039 7.07 7.32 1
A/C Water-cooled chiller electronically operated, reciprocating and positive
displacement
Code standards Tons ENComm_Cooling 20 212.96 $313.75 – $38.82 $40.00 $0.039 6.50 7.32 6
A/C Airside economizer Code standards Ton of cooling ENComm_Cooling 15 190.00 $219.25 – $81.36 $75.00 $0.039 2.66 2.72 6
A/C Direct evaporative cooler
IECC 2009
Code standards Tons ENComm_Cooling 15 399.00 $460.42 – $364.00 $200.00 $0.039 2.14 1.33 1
A/C Direct evaporative cooler IECC 2012 Code standards Tons ENComm_Cooling 15 386.00 $445.42 – $364.00 $200.00 $0.039 2.07 1.29 1
Evaporative Pre-
Cooler
Pre-cooler added
to condenser
Standard
air-cooled chiller unit
Ton IPC_Evap Cooler
(ky)
15 106.00 $169.37 – $173.00 $20.00 $0.039 7.02 1.05 1
Building Shell Reflective roof treatment Code standards ft2 roof area ENComm_Cooling 15 0.12 $0.13 – $0.05 $0.05 $0.039 2.46 2.70 1
Controls Energy Management
System (EMS) controls. Part A: 2 strategies
Code standards Tons of
cooling
ENComm_Cooling 15 418.00 $482.34 – $162.49 $70.00 $0.039 5.59 2.97 1
Controls EMS controls.
Part B: 3 strategies
Code standards Tons of
cooling
ENComm_Cooling 15 484.00 $558.50 – $162.49 $80.00 $0.039 5.65 3.39 7
Controls EMS controls.
Part C: 4 strategies
Code standards Tons of
cooling
ENComm_Cooling 15 484.00 $558.50 – $162.49 $90.00 $0.039 5.13 3.39 1
Controls EMS controls. Part D: 5 strategies Code standards Tons of cooling ENComm_Cooling 15 633.00 $730.44 – $162.49 $100.00 $0.039 5.86 4.29 7
Controls Guest room energy
mananagement system IECC 2009
Code standards Ton ENComm_HVAC 11 581.00 $444.20 – $57.50 $50.00 $0.039 6.11 6.10 1
Controls Guest room energy mananagement system
IECC 2012
Code standards Ton ENComm_HVAC 11 572.00 $437.32 – $57.50 $50.00 $0.039 6.05 6.03 1
Controls Part A. Variable speed drive on HVAC system
applications:• Chilled water pumps
• Condenser water pumps• Cooling tower fans
Code standards HP ENComm_HVAC 15 268.00 $265.98 – $165.33 $60.00 $0.039 3.78 1.66 1
Controls Part B. Variable speed drive on HVAC system
applications:• Supply
• Return• Outside air• Make-up air
• Hot water pumps
Code standards HP ENComm_HVAC 15 996.00 $988.48 – $142.05 $100.00 $0.039 7.12 6.01 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 53
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e
UC Ratiof
TRC Ratiog Source
Variable-speed controls Part C: Variable speed drive on Potato/Onion Storage Shed Ventilation
No variable speed drive (VSD)
Horsepower IPC_Onion Potato VSD 10 1,993.00 $1,017.52 – $300.00 $200.00 $0.039 3.66 2.96 8
Demand Controlled
Kitchen Ventilation
Exhaust Hood
Demand Controlled Kitchen Ventilation Exhaust Hood Kitchen ventilation hood Horsepower ENComm_Cooking 15 3,838.00 $3,464.54 – $2,000.00 $200.00 $0.039 9.91 1.77 9
Appliances with Electric Water Heating
Efficient Laundry Machines (electric)Code standards Unit ENComm_WtrHtr 10 756.00 $452.14 – $200.00 $125.00 $0.039 2.93 2.17 1
Appliances with Electric Water Heating
ENERGY STAR®
undercounter (residential style) dishwasher
Code standards Machine ENComm_Misc 12 2,210.00 $1,593.82 $245.73 $232.00 $200.00 $0.039 5.57 6.28 1, 10
Appliances with Electric Water Heating
ENERGY STAR commercial dishwasher Code standards Machine ENComm_Misc 12 5,561.00 $4,010.51 $662.72 $3,978.00 $500.00 $0.039 5.60 1.21 1, 10
Refrigeration Refrigeration head pressure
controls
Code standards Horsepower ENComm_
Refrigeration
16 225.00 $208.41 – $166.60 $40.00 $0.039 4.27 1.31 1
Refrigeration Refrigeration floating suction controls Code standards Horsepower ENComm_Refrigeration 16 77.00 $71.32 – $53.75 $10.00 $0.039 5.49 1.38 1
Refrigeration Efficient refrigeration
condensers
Code standards Tons of
refrigeration
ENComm_
Refrigeration
15 114.00 $99.24 – $35.00 $20.00 $0.039 4.06 2.77 1
Smart Power Strips Load-sensing, motion-sensing, or timer-controlled
power strip
No exisiting load or motion-
sensing, or timer-controlled power strip
Power strip ENComm_Office 4 118.00 $29.03 – $21.00 $10.00 $0.039 1.99 1.25 11
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 Idaho Power TRM prepared by ADM Associates, Inc. 2015.
2 Measure not cost-effective.
3 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Weighted average of 5–25 ton units.
4 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Weighted average of 0–25 ton units.5 Measure not cost-effective. Measure to be monitored in 2017. Measure included in the program to increase participation in a cost-effective program and to encourage adoption of higher efficiency equipment.
6 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Averaged water cooled chillers.
7 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Calculated from TRM spreadsheets.
8 RTF. AgPotatoOnionShedVFD_v3_0.xlsm. IPC Costs.
9 IPC engineering analysis.10 Idaho Power TRM prepared by ADM Associates, Inc. 2015. NEBs from water savings from RTF. ComDishwasher_v1_2.xlsm. 2012.
11 RTF. ComSmartPlugPower_v3_1.xlsm. Updated incremental costs based on IPC research.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 54 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 55
Custom Projects (Custom Efficiency)
Segment: Industrial2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ................................................$41,986,723 $7,982,624 5.26
TRC Test ..............................................46,185,395 16,123,619 2.86
RIM Test ...............................................41,986,723 29,195,882 1.44
PCT ......................................................27,327,501 14,255,237 1.92
Cost Inputs Ref
Program Administration ..........................................................................$ 1,868,381
Program Incentives................................................................................. 6,114,243 I
Total UC .................................................................................................$ 7,982,624 P
Measure Equipment and Installation (Incremental Participant Cost)......$ 14,255,237 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)...........................47,518,871
NPV Cumulative Energy (kWh) ...............................549,397,237 $41,986,723 S
10% Credit (Northwest Power Act)..........................4,198,672
Total Electric Savings ................................................$46,185,395 A
Participant Bill Savings
NPV Cumulative Participant Savings ......................$21,213,258 B
Other Benefits
Non-Utility Rebates/Incentives ................................$–NUI
NEBs .......................................................................$–NEB
Benefits and Costs Included in Each Test
UC Test .............................................= S * NTG = P
TRC Test ...........................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ...........................................= S * NTG = P + (B * NTG)
PCT ...................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................21%
Average Customer Segment Rate/kWh ..............................................................$0.037
Line Losses .........................................................................................................9.60%
Notes: Energy savings are unique by project and are reviewed by Idaho Power engineering staff or third-party consultants. Each project must complete a certification inspection. Green Rewind initiative is available to agricultural, commercial, and industrial customers. Commercial and industrial motor rewinds are paid under Custom Projects, but the savings are not included in the program
cost-effectiveness. Green Rewind savings are included in the sector cost-effectiveness.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 56 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name
Measure
Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Green Motors Program Rewind:
Motor size 15 HP
Green Motors Program Rewind:
Motor size 15 HP
Standard rewind practice Motor MF_Motors 8 601.00 $301.14 – $153.77 $30.00 $0.050 5.01 1.80 1
Green Motors Program Rewind:
Motor size 20 HP
Green Motors Program Rewind:
Motor size 20 HP
Standard rewind practice Motor MF_Motors 8 804.00 $402.86 – $171.56 $40.00 $0.050 5.02 2.09 1
Green Motors Program Rewind: Motor size 25 HP
Green Motors Program Rewind: Motor size 25 HP
Standard rewind practice Motor MF_Motors 8 1,052.00 $527.13 – $196.01 $50.00 $0.050 5.14 2.33 1
Green Motors Program Rewind: Motor size 30 HP
Green Motors Program Rewind: Motor size 30 HP
Standard rewind practice Motor MF_Motors 8 1,133.00 $567.71 – $215.29 $60.00 $0.050 4.87 2.30 1
Green Motors Program Rewind: Motor size 40 HP
Green Motors Program Rewind: Motor size 40 HP
Standard rewind practice Motor MF_Motors 8 1,319.00 $660.91 – $263.09 $80.00 $0.050 4.53 2.21 1
Green Motors
Program Rewind: Motor size 50 HP
Green Motors
Program Rewind: Motor size 50 HP
Standard rewind
practice
Motor MF_Motors 8 1,418.00 $710.52 – $291.24 $100.00 $0.050 4.16 2.16 1
Green Motors
Program Rewind: Motor size 60 HP
Green Motors
Program Rewind: Motor size 60 HP
Standard rewind
practice
Motor MF_Motors 9 1,476.00 $825.50 – $343.49 $120.00 $0.050 4.26 2.18 1
Green Motors
Program Rewind: Motor size 75 HP
Green Motors
Program Rewind: Motor size 75 HP
Standard rewind
practice
Motor MF_Motors 9 1,519.00 $849.55 – $371.28 $150.00 $0.050 3.76 2.09 1
Green Motors Program Rewind: Motor size 100 HP
Green Motors Program Rewind: Motor size 100 HP
Standard rewind practice Motor MF_Motors 9 2,005.00 $1,121.36 – $460.58 $200.00 $0.050 3.73 2.20 1
Green Motors Program Rewind:
Motor size 125 HP
Green Motors Program Rewind:
Motor size 125 HP
Standard rewind practice Motor MF_Motors 8 2,598.00 $1,301.78 – $517.27 $250.00 $0.050 3.43 2.21 1
Green Motors Program Rewind:
Motor size 150 HP
Green Motors Program Rewind:
Motor size 150 HP
Standard rewind practice Motor MF_Motors 8 3,089.00 $1,547.80 – $576.19 $300.00 $0.050 3.41 2.33 1
Green Motors Program Rewind:
Motor size 200 HP
Green Motors Program Rewind:
Motor size 200 HP
Standard rewind practice Motor MF_Motors 8 4,088.00 $2,048.37 – $693.65 $400.00 $0.050 3.39 2.51 1
Green Motors Program Rewind: Motor size 250 HP
Green Motors Program Rewind: Motor size 250 HP
Standard rewind practice Motor MF_Motors 9 4,972.00 $2,780.75 – $891.52 $500.00 $0.050 3.71 2.68 1
Green Motors Program Rewind: Motor size 300 HP
Green Motors Program Rewind: Motor size 300 HP
Standard rewind practice Motor MF_Motors 9 5,935.00 $3,319.34 – $901.16 $600.00 $0.050 3.70 3.05 1
Green Motors
Program Rewind: Motor size 350 HP
Green Motors
Program Rewind: Motor size 350 HP
Standard rewind
practice
Motor MF_Motors 9 6,919.00 $3,869.68 – $944.51 $700.00 $0.050 3.70 3.30 1
Year: 2016 Program: Custom Projects Market Segment: Industrial Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 57
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Green Motors Program Rewind: Motor size 400 HP
Green Motors Program Rewind: Motor size 400 HP
Standard rewind practice Motor MF_Motors 9 7,848.00 $4,389.25 – $1,054.93 $800.00 $0.050 3.68 3.34 1
Green Motors Program Rewind:
Motor size 450 HP
Green Motors Program Rewind:
Motor size 450 HP
Standard rewind practice Motor MF_Motors 9 8,811.00 $4,927.84 – $1,153.12 $900.00 $0.050 3.68 3.40 1
Green Motors Program Rewind:
Motor size 500 HP
Green Motors Program Rewind:
Motor size 500 HP
Standard rewind practice Motor MF_Motors 9 9,804.00 $5,483.21 – $1,245.76 $1,000.00 $0.050 3.68 3.47 1
Green Motors Program Rewind:
Motor size 600 HP
Green Motors Program Rewind:
Motor size 600 HP
Standard rewind practice Motor MF_Motors 7 14,689.00 $6,474.07 – $1,835.78 $1,200.00 $0.050 3.35 2.77 1
Green Motors Program Rewind: Motor size 700 HP
Green Motors Program Rewind: Motor size 700 HP
Standard rewind practice Motor MF_Motors 7 17,065.00 $7,521.27 – $2,002.84 $1,400.00 $0.050 3.34 2.90 1
Green Motors Program Rewind: Motor size 800 HP
Green Motors Program Rewind: Motor size 800 HP
Standard rewind practice Motor MF_Motors 7 19,461.00 $8,577.29 – $2,222.20 $1,600.00 $0.050 3.33 2.95 1
Green Motors Program Rewind: Motor size 900 HP
Green Motors Program Rewind: Motor size 900 HP
Standard rewind practice Motor MF_Motors 7 21,847.00 $9,628.90 – $2,449.87 $1,800.00 $0.050 3.33 2.99 1
Green Motors
Program Rewind: Motor size
1,500 HP
Green Motors
Program Rewind: Motor size
1,500 HP
Standard rewind
practice
Motor MF_Motors 7 35,891.00 $15,818.69 – $3,612.90 $3,000.00 $0.050 2.28 2.30 1
Green Motors Program Rewind: Motor size 3,000 HP
Green Motors Program Rewind: Motor size 3,000 HP
Standard rewind practice Motor MF_Motors 7 70,147.00 $30,916.76 – $6,446.18 $6,000.00 $0.050 2.24 2.39 1
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. IndGreenMotorsRewind_v2_0.xlsm. 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 58 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 59
Retrofits (Easy Upgrades)
Segment: Commercial2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ..................................................$19,291,267 $5,040,190 3.83
TRC Test ................................................21,220,394 8,038,791 2.64
RIM Test .................................................19,291,267 20,656,062 0.93
PCT ........................................................19,503,834 6,886,563 2.83
Cost Inputs Ref
Program Administration ...........................................................................$ 1,152,228
Program Incentives..................................................................................3,887,962 I
Total UC ..................................................................................................$5,040,190 P
Measure Equipment and Installation (Incremental Participant Cost).......$6,886,563 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh)..............................28,124,779
NPV Cumulative Energy (kWh) ..................................272,414,144 $19,291,267 S
10% Credit (Northwest Power Act).............................1,929,127
Total Electric Savings ...................................................$21,220,394 A
Participant Bill Savings
NPV Cumulative Participant Savings .........................$15,615,872 B
Other Benefits
Non-Utility Rebates/Incentives ...................................$–NUI
NEBs ..........................................................................$–NEB
Benefits and Costs Included in Each Test
UC Test .............................................= S * NTG = P
TRC Test ...........................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ...........................................= S * NTG = P + (B * NTG)
PCT ..................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................28%
Average Customer Segment Rate/kWh ..............................................................$0.057
Line Losses .........................................................................................................9.60%
Note: Measure inputs from Evergreen Consulting Group or the TRM prepared by ADM Associates, Inc., unless otherwise noted.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 60 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Standard/High Performance T8 Fluorescents
4-foot T8 4-foot T12 Fixture ENComm_InsLt 11 180.28 $125.18 – $61.15 $34.42 $0.039 3.02 2.02 1
Standard T8 Fluorescents 6-foot T8 6-foot T12 Fixture ENComm_InsLt 11 332.20 $230.66 – $76.03 $16.00 $0.039 7.97 2.85 1
Standard T8 Fluorescents 8-foot T8 8-foot T12 Fixture ENComm_InsLt 11 262.06 $181.96 – $80.56 $22.75 $0.039 5.52 2.21 1
Standard/High Performance T8 Fluorescents
4-foot & 8-foot T8 8-foot T12HO Fixture ENComm_InsLt 11 564.84 $392.19 – $75.36 $47.52 $0.039 5.64 4.43 1
T5 (Non-HO)
Fluorescents
4-foot T5 4-foot T12 Fixture ENComm_InsLt 11 156.85 $108.91 – $76.21 $36.18 $0.039 2.58 1.46 1
T5/T8 High Bay—
New Fixture
4-foot T8/T5 Fixture using >200 input watts Fixture ENComm_InsLt 11 1,194.00 $829.04 – $216.24 $137.04 $0.039 4.52 3.47 1
Relamp T8/T5HO to
Reduced Wattage T8/T5HO
Reduced wattage T8/T5 re-lamp Fixture ENComm_InsLt 8 130.58 $67.81 – $23.07 $1.00 $0.039 11.14 2.65 1
Permanent Fixture Removal Permanent fixture removal Fixture ENComm_InsLt 8 878.14 $456.05 – $35.78 $19.09 $0.039 8.55 7.17 1
Screw-in CFLs/cold-cathode Screw-in CFLs/cold-cathode Fixture using >40 input watts Fixture ENComm_InsLt 6 164.23 $64.51 – $33.23 $5.08 $0.039 5.62 1.79 1
Hardwired CFLs Hardwired CFLs Fixture using >90 input watts Fixture ENComm_InsLt 6 366.94 $144.13 – $94.75 $50.00 $0.039 2.24 1.45 1
LED Replacement
Lamps
LED replacement lamps Fixture using >20 input watts Fixture ENComm_InsLt 12 154.10 $115.42 – $48.66 $15.00 $0.039 5.49 2.32 1
Pulse Start/Electronic Metal
Halide
Pulse start/electronic metal halide Fixture using >170 input watts Fixture ENComm_InsLt 11 1,091.70 $758.01 – $153.66 $105.55 $0.039 5.12 4.25 1
LED Exit Sign LED exit sign Exit sign using ≥18 watts Fixture IPC_8760 12 230.68 $157.63 – $68.69 $40.00 $0.039 3.22 2.23 1
Lighting Controls Lighting controls Manual controls Fixture ENComm_InsLt 10 187.75 $119.78 – $94.75 $47.51 $0.039 2.18 1.29 1
Standard/High
Performance T8 Fluorescents
4-foot T8 4-foot T12 Fixture IPC_Outdoor Lighting 11 166.42 $77.49 – $61.15 $13.80 $0.039 3.82 1.26 1
Standard T8
Fluorescents
6-foot T8 6-foot T12 Fixture IPC_Outdoor Lighting 11 386.42 $179.92 – $76.03 $14.00 $0.039 6.19 2.17 1
Standard T8 Fluorescents 8-foot T8 8-foot T12 Fixture IPC_Outdoor Lighting 11 303.92 $141.51 – $80.56 $19.50 $0.039 4.51 1.68 1
Year: 2016 Program: Retrofits Market Segment: Commercial Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 61
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Standard/High-Performance T8 Fluorescents
4-foot & 8-foot T8 8-foot T12HO Fixture IPC_Outdoor Lighting 11 913.16 $425.18 – $75.36 $21.48 $0.039 7.45 4.22 1
T5 (Non-HO) Fluorescents 4-foot T5 4-foot T12 Fixture IPC_Outdoor Lighting 11 181.22 $84.38 – $76.21 $20.47 $0.039 3.06 1.11 1
T5/T8 High Bay—New
Fixture
4-foot T8/T5 Fixture using >200 input watts Fixture IPC_Outdoor Lighting 11 1,643.60 $765.28 – $216.24 $102.71 $0.039 4.59 3.00 1
Permanent Fixture Removal Permanent Fixture Removal Fixture IPC_Outdoor Lighting 8 1,018.40 $350.76 – $35.78 $14.09 $0.039 6.52 5.11 1
Screw-in CFLs/
cold-cathode
Screw-in CFLs/cold-
cathode
Fixture using
>40 input watts
Fixture IPC_Outdoor Lighting 6 190.46 $48.86 – $33.23 $5.08 $0.039 3.91 1.32 1
Hardwired CFLs Hardwired CFLs Fixture using >90 input watts Fixture IPC_Outdoor Lighting 6 425.55 $109.18 – $94.75 $35.00 $0.039 2.12 1.08 1
LED
Replacement Lamps
LED Replacement Lamps Fixture using
>20 input watts
Fixture IPC_Outdoor Lighting 12 178.71 $90.05 – $48.66 $19.25 $0.039 3.43 1.78 1
Pulse Start/
Electronic Metal Halide
Pulse Start/Electronic
Metal Halide
Fixture using
>170 input watts
Fixture IPC_Outdoor Lighting 11 1,265.40 $589.18 – $153.66 $45.68 $0.039 6.20 3.19 1
Refrigeration
Case Lighting
Case # 1—T8 fluorescent
lighting and electronic ballast (per lamp)
Case #1—
T12 fluorescent lighting
Lamp ENComm_
Refrigeration
6 309.31 $116.64 – $44.70 $15.00 $0.039 4.31 2.26 2
Refrigeration Case Lighting Case # 2—LED display case lighting (per linear foot)
Case #2—T12 fluorescent lighting
Linear foot ENComm_Refrigeration 8 111.25 $55.52 $17.21 $42.56 $15.00 $0.039 2.87 1.67 3
Refrigeration Case Lighting Case # 3—LED display case lighting (per linear
foot)
Case #3—T8 fluorescent
lighting
Linear foot ENComm_Refrigeration 8 77.75 $38.80 $15.95 $44.21 $10.00 $0.039 2.98 1.24 4
Refrigeration Case Lighting Case #4—TLED display case lighting Case #4—T12 fluorescent
lighting
Linear foot ENComm_Refrigeration 12 34.49 $24.84 $2.48 $8.48 $1.50 $0.039 8.73 3.03 5
Refrigeration Case Lighting Case #5—TLED display case lighting Case #5—T8 fluorescent
lighting
Linear foot ENComm_Refrigeration 12 9.86 $7.10 $2.48 $8.48 $1.50 $0.039 3.77 1.16 5
A/C Units ≤5 ton A/C unit that meets CEE Tier 2 >5–11 ton A/C unit that
meets CEE Tier 2 >11–19 ton A/C unit that
meets CEE Tier 2 >19–25 ton A/C unit that meets CEE Tier 2
(≤300,000 Btu/hr)
Standard ≤5 ton A/C/HP unit Standard >5–11
ton A/C/HP unit Standard >11–19
ton A/C/HP unit Standard >19–25 ton A/C/HP unit
(code standard)
Tons ENComm_Cooling 15 90.16 $104.04 – $115.37 $75.00 $0.039 1.33 0.96 6, 7
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 62 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
A/C Units >5–11 ton A/C unit that meets CEE Tier 1 >11–19 ton A/C unit that
meets CEE Tier 1 >19–25 ton A/C unit that
meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Standard >5–11 ton A/C/HP unit Standard >11–19
ton A/C/HP unit Standard >19–25
ton A/C/HP unit (code standard)
Tons ENComm_Cooling 15 96.30 $111.12 – $81.57 $30.00 $0.039 3.29 1.43 8
A/C Units >5–11 ton A/C VRF unit that meets CEE Tier 1 >11–19 ton A/C VRF unit
that meets CEE Tier 1 >19–25 ton A/C VRF unit that meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Standard >5–11 ton A/C/HP unit Standard >11–19
ton A/C/HP unit Standard >19–25 ton A/C/HP unit (code standard)
Tons ENComm_Cooling 15 188.51 $217.53 – $161.54 $75.00 $0.039 2.64 1.42 8
Heat Pump (HP)
units
≤5 ton HP unit that meets
CEE Tier 1 >5–11 ton HP unit that
meets CEE Tier 1 >11–19 ton HP unit that meets CEE Tier 1
>19–25 ton HP unit that meets CEE Tier 1
(≤300,000 Btu/hr)
Standard ≤5 ton
A/C/HP unit Standard >5–11
ton A/C/HP unit Standard >11–19 ton A/C/HP unit
Standard >19–25 ton A/C/HP unit
(code standard)
Tons ENComm_Cooling 15 45.18 $52.13 – $28.03 $30.00 $0.039 1.64 1.93 6
HP Units >5–11 ton HP VRF unit that meets CEE Tier 1 >11–19 ton HP VRF unit that meets CEE Tier 1 >19–25 ton HP VRF unit
that meets CEE Tier 1 (≥65,000 Btu/hr & ≤300,000 Btu/hr)
Standard >5–11 ton A/C/HP unit Standard >11–19 ton A/C/HP unit Standard >19–25
ton A/C/HP unit (code standard)
Tons ENComm_Cooling 15 56.80 $65.54 – $91.88 $75.00 $0.039 0.85 0.77 7, 8
Chillers Air-cooled chiller condenser, IPLV 14.0 EER or higher
Standard air-cooled chiller Tons ENComm_Cooling 20 472.44 $696.03 – $86.12 $80.00 $0.039 7.07 7.32 9
Chillers Water-cooled chiller electronically operated, reciprocating and positive
displacement
Standard water-cooled chiller Tons ENComm_Cooling 20 212.96 $313.75 – $38.82 $40.00 $0.039 6.50 7.32 10
Economizers Airside economizer control addition No prior control Ton of cooling ENComm_Cooling 15 285.00 $328.87 – $155.01 $100.00 $0.039 2.96 2.18 9
Economizers Airside economizer
control repair
Non-functional
economizer
Ton of
cooling
ENComm_Cooling 15 285.00 $328.87 – $73.65 $50.00 $0.039 5.38 4.27 9
Evaporative coolers/
Pre-coolers
Direct evaporative cooler Replacing standard A/C unit Tons ENComm_Cooling 15 386.00 $445.42 – $364.00 $200.00 $0.039 2.07 1.29 9
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 63
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Automated Controls EMS controls with 2 strategies Proposed strategy not existing (retrofit system)
Tons of cooling ENComm_Cooling 15 636.00 $733.90 – $197.98 $125.00 $0.039 4.90 3.62 9
Automated Controls EMS controls with 3 strategies Proposed strategy not existing (retrofit system)
Tons of cooling ENComm_Cooling 15 794.00 $916.22 – $197.98 $150.00 $0.039 5.06 4.40 11
Automated
Controls
EMS controls with
4 strategies
Proposed strategy
not existing (retrofit system)
Tons of
cooling
ENComm_Cooling 15 794.00 $916.22 – $197.98 $175.00 $0.039 4.45 4.40 9
Automated
Controls
EMS controls with
5 strategies
Proposed strategy
not existing (retrofit system)
Tons of
cooling
ENComm_Cooling 15 1,842.00 $2,125.54 – $197.98 $200.00 $0.039 7.82 8.67 11
Automated
Controls
EMS controls with
2 strategies
Proposed strategy
not existing (new system)
Tons of
cooling
ENComm_Cooling 15 418.00 $482.34 – $162.49 $70.00 $0.039 5.59 2.97 9
Automated Controls EMS controls with 3 strategies Proposed strategy not existing (new system)
Tons of cooling ENComm_Cooling 15 484.00 $558.50 – $162.49 $80.00 $0.039 5.65 3.39 11
Automated Controls EMS controls with 4 strategies Proposed strategy not existing
(new system)
Tons of cooling ENComm_Cooling 15 484.00 $558.50 – $162.49 $90.00 $0.039 5.13 3.39 9
Automated Controls EMS controls with 5 strategies Proposed strategy not existing
(new system)
Tons of cooling ENComm_Cooling 15 633.00 $730.44 – $162.49 $100.00 $0.039 5.86 4.29 11
Automated Controls Lodging room occupancy controls Manual controls Ton ENComm_HVAC 11 665.00 $508.42 – $150.61 $75.00 $0.039 5.04 3.17 9
Evaporative
Pre-Cooler
Pre-cooler added
to condenser
Standard air-
cooled chiller unit
Ton IPC_Evap Cooler (ky)15 106.00 $169.37 – $173.00 $20.00 $0.039 7.02 1.05 9
Electronically Commutated
Motor (ECM)
ECM motor in HVAC application Shaded pole or permanent split
capacitor motor
Motor ENComm_HVAC 15 724.00 $718.54 – $140.00 $100.00 $0.039 5.60 4.70 5
Notched V-Belt in HVAC Applications
Type AX notched V-belt Type BX notched V-belt Type A solid V-belt Type B solid
V-belt
hp ENComm_HVAC 6 54.92 $23.94 – $7.52 $5.00 $0.039 3.35 2.73 5
Premium Windows Low U-value, U-factor of .30 or less Standard windows ft2 window area ENComm_HVAC 25 5.89 $8.93 – $5.92 $2.50 $0.039 3.27 1.60 9
Reflective
Roofing
Adding reflective roof
treatment
Non-reflective low
pitch roof
ft2 roof area ENComm_Cooling 15 0.12 $0.13 – $0.05 $0.05 $0.039 2.46 2.70 9
Wall Insulation Increase to R11 min. insulation Insulation level, R2.5 or less ft2 wall area ENComm_HVAC 25 0.41 $0.63 – $0.66 $0.40 $0.039 1.51 1.02 9
Wall Insulation Increase to R19 min.
insulation
Insulation level,
R2.5 or less
ft2 wall area ENComm_HVAC 25 0.47 $0.71 – $0.66 $0.55 $0.039 1.24 1.14 9
Computers PC network power management No central control software in place Unit ENComm_Office 4 135.00 $33.21 – $12.00 $10.00 $0.039 2.18 2.12 9
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 64 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Laundry Machines High efficiency washer Standard washer, electric HW Unit ENComm_WtrHtr 10 756.00 $452.14 – $200.00 $125.00 $0.039 2.93 2.17 9
Stock Tank/Fountain Energy free freeze-resistant stock tank Thermostatically controlled electric resistance element freeze
protection
Unit Comm_Agriculture 10 1,176.00 $979.19 – $431.76 $100.00 $0.039 6.71 2.26 12
Residential-Type Electric Water
Heater
EF 0.94 or higher, 25–54 gallon
EF 0.95 or higher, 45–54 gallon EF 0.93 or higher,
55–74 gallon EF 0.92 or higher,
75–99 gallon EF 0.85 or higher, 100–119 gallon
Standard electric water heater Unit ENComm_WtrHtr 13 154.14 $116.16 – $66.22 $50.00 $0.039 2.07 1.77 13
Commercial-Type Electric Water Heater
25–34 gallon, standby loss 157 or lower 35–44 gallon, standby
loss 185 or lower 45–54 gallon, standby loss 201 or lower 55–74 gallon, standby loss 238 or lower
75–99 gallon, standby by loss 249 or lower 100–119 gallon, standby loss 287 or lower
Standard electric water heater Unit ENComm_WtrHtr 13 68.17 $51.37 – $29.00 $20.00 $0.039 2.27 1.78 14
Commercial Showerhead,
Electric Water Heat
2.0 gpm or less installed in health club/fitness
business
Showerhead using 2.2 gpm
or greater
Unit ENComm_WtrHtr 10 2,431.00 $1,453.91 – $13.00 $15.00 $0.039 13.25 14.84 15
Commercial
Showerhead, Electric Water Heat
2.0 gpm or less installed
in commercial business (non-health club/fitness business)
Showerhead
using 2.2 gpm or greater
Unit ENComm_WtrHtr 10 129.00 $77.15 – $13.00 $9.00 $0.039 5.50 4.71 15
Smart Power Strips Load-sensing, motion-sensing, or timer-controlled power strip
No exisiting load or motion-sensing, or
timer-controlled power strip
Power strip ENComm_Office 4 118.00 $29.03 – $21.00 $10.00 $0.039 1.99 1.25 16
Standby
Generator Engine Block Heater
Stationary pump-
driven circulating block heater; must operate continuously
Thermosiphon
electric resistance circulating block heater <3 kW
Unit IPC_Engine Block 10 3,415.00 $1,537.79 – $1,287.31 $200.00 $0.039 4.62 1.19 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 65
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Standby Generator Engine Block
Heater
Stationary pump-driven circulating block heater; must operate
continuously
Thermosiphon electric resistance circulating block
heater 3 kW or greater
Unit IPC_Engine Block 10 17,524.00 $7,891.14 – $3,090.77 $1,500.00 $0.039 3.62 2.30 5
Refrigeration Add refrigeration line
insulation
No insulation
present
Linear ft ENComm_
Refrigeration
11 9.75 $6.51 – $4.46 $2.00 $0.039 2.73 1.48 9
Refrigeration Install auto-closer—walk-in No/damaged auto-closer,
low temp
Door ENComm_Refrigeration 8 2,547.00 $1,271.15 – $139.32 $125.00 $0.039 5.67 5.86 9
Refrigeration Install auto-closer—reach-in Damaged auto-closer, low temp Door ENComm_Refrigeration 8 560.00 $279.48 – $139.32 $100.00 $0.039 2.29 1.91 9
Refrigeration Install auto-closer—
walk-in
No/damaged
auto-closer, med. temp
Door ENComm_
Refrigeration
8 575.00 $286.97 – $139.32 $100.00 $0.039 2.34 1.95 9
Refrigeration Install auto-closer—reach-in Damaged auto-closer, med. temp Door ENComm_Refrigeration 8 373.00 $186.16 – $139.32 $70.00 $0.039 2.20 1.33 9
Refrigeration Add anti-sweat heat controls Low/med. temp case w/out controls
Linear ft ENComm_Refrigeration 8 208.00 $103.81 – $40.00 $40.00 $0.039 2.16 2.37 9
Evaporative Fans Add evaporative fan controls Low or med.temp. walk-in or reach-in with no
controls
Fan ENComm_Refrigeration 15 408.00 $355.17 – $161.74 $75.00 $0.039 3.91 2.20 9
Evaporative Fans Install ECM/PSC evap fan motor Med. or low temp. walk-in Motor ENComm_Refrigeration 15 593.00 $516.21 – $296.78 $100.00 $0.039 4.19 1.78 9
Evaporative
Fans
Install ECM/PSC evap
fan motor
Med. or low temp.
reach-in
Motor ENComm_
Refrigeration
15 318.00 $276.82 – $84.45 $60.00 $0.039 3.82 3.14 9
Floating Head/Suction
Pressures
Head pressure controller Standard head pressure control Horsepower ENComm_Refrigeration 16 440.00 $407.55 – $272.60 $80.00 $0.039 4.20 1.55 9
Floating Head/Suction Pressures
Suction pressure controller Standard suction pressure control Horsepower ENComm_Refrigeration 16 104.00 $96.33 – $86.91 $20.00 $0.039 4.00 1.16 9
Demand Controlled Kitchen
Ventilation Exhaust Hood
VFD installed on kitchen exhaust and/or makeup air fan
Kitchen hood with constant speed ventilation
HP ENComm_Cooking 15 3,838.00 $3,464.54 – $2,000.00 $200.00 $0.039 9.91 1.77 5
Vending
Machines
Non-cooled snack control Vending machine
with no sensor
Sensor ENComm_Misc 5 387.00 $121.79 – $75.00 $50.00 $0.039 1.87 1.49 9
Commercial kitchen
equipment
ENERGY STAR® undercounter (residential
style) dishwasher
Standard dishwasher Machine ENComm_Misc 12 2,210.00 $1,593.82 $245.73 $232.00 $200.00 $0.039 5.57 6.28 17
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 66 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Commercial kitchen equipment
ENERGY STAR commercial dishwasher Standard commercial dishwasher
Machine ENComm_Misc 12 5,561.00 $4,010.51 $662.72 $3,978.00 $500.00 $0.039 5.60 1.21 17
Commercial kitchen equipment
ENERGY STAR listed electric combination oven (6–14 pans)
Standard electric oven Oven ENComm_Cooking 10 12,999.00 $8,269.44 – $1,632.82 $1,100.00 $0.039 5.15 4.25 18
Commercial
kitchen equipment
ENERGY STAR listed
electric combination oven (15–20 pans)
Standard electric
oven
Oven ENComm_Cooking 10 17,877.00 $11,372.62 – $446.11 $300.00 $0.039 11.41 10.95 18
Commercial
kitchen equipment
ENERGY STAR listed
electric convection oven
Standard electric
oven
Oven ENComm_Cooking 10 1,672.00 $1,063.66 – $923.04 $300.00 $0.039 2.91 1.18 19
Commercial
kitchen equipment
ENERGY STAR listed
electric fryer
Standard fryer Fryer ENComm_Cooking 8 2,671.00 $1,382.96 – $788.29 $400.00 $0.039 2.74 1.70 20
Commercial kitchen equipment
ENERGY STAR listed electric steamer—3 pan Standard steamer Steamer ENComm_Cooking 9 21,470.00 $12,409.31 – $361.17 $80.00 $0.039 13.54 11.40 21
Commercial kitchen
equipment
ENERGY STAR listed electric steamer—4 pan Standard steamer Steamer ENComm_Cooking 9 28,564.00 $16,509.52 – $137.86 $100.00 $0.039 13.61 14.52 21
Commercial kitchen
equipment
ENERGY STAR listed electric steamer—5 pan Standard steamer Steamer ENComm_Cooking 9 35,659.00 $20,610.31 – $(270.07) $150.00 $0.039 13.39 20.25 21
Commercial kitchen
equipment
ENERGY STAR listed electric steamer—6 pan Standard steamer Steamer ENComm_Cooking 9 42,754.00 $24,711.11 – $59.79 $175.00 $0.039 13.42 15.75 21
Commercial kitchen equipment
ENERGY STAR listed electric steamer—10 pan or larger
Standard steamer Steamer ENComm_Cooking 9 71,133.00 $41,113.70 – $4,094.23 $200.00 $0.039 13.83 6.59 21
Variable-speed controls Variable-speed drive on HVAC system applications:
• Chilled water pumps• Condenser water
pumps• Cooling tower fans
Single speed HVAC system fan/pump
HP ENComm_HVAC 15 268.00 $265.98 – $165.33 $60.00 $0.039 3.78 1.66 9
Variable-speed controls Variable-speed drive on HVAC system
applications:• Supply
• Return• Outside air• Make-up air
• Hot water pumps
Single speed HVAC system
fan/pump
HP ENComm_HVAC 15 996.00 $988.48 – $142.05 $100.00 $0.039 7.12 6.01 9
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 67
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure unit End Use
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc NEB
Gross
Incremental Participant Costd
Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Variable-speed controls Variable-speed drive (VSD) on potato and onion storage shed
ventilation
No existing VSD HP IPC_Onion Potato VSD 10 1,993.00 $1,017.52 – $300.00 $200.00 $0.039 3.66 2.96 22
a Average measure life.
b Estimated kWh savings measured at the customer’s meter, excluding line losses.
c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.
f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))1 Evergreen Consulting Group, LLC. Idaho Power Lighting Tool. 2016.
2 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential—Commercial Model 081209.xlsm. 2009.
3 RTF. ComGroceryDisplayCaseLEDs_v2_2 and ComGroceryCaseLEDs_v1.1.xls. 2013. T12 to LED. Averaged the measures for less than 4 watts/linear foot (W/ln ft) and 4–8.5 W/ln ft.
4 RTF. ComGroceryDisplayCaseLEDs_v2_2 and ComGroceryCaseLEDs_v1.1.xls. 2013. T8 to LED. Averaged the measures for less than 4 W/ln ft and 4–8.5 W/ln ft.
5 IPC engineering analysis.6 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Weighted average of 0–25 ton units.
7 Measure not cost-effective. Measure to be monitored in 2017. Measure included in the program to increase participation in a cost-effective program and to encourage adoption of higher-efficiency equipment.
8 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Weighted average of 5–25 ton units.
9 Idaho Power TRM prepared by ADM Associates, Inc. 2015.
10 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Averaged water cooled chillers.11 Idaho Power TRM prepared by ADM Associates, Inc. 2016. Calculated from TRM spreadsheets.
12 RTF. AgStockWateringTank_v2_0.xlsm. 2013. Simple average of heating zones 1, 2, & 3.
13 RTF. ComDHWEfficientTank_v3_0.xlsm. 2014. Simple average of residential style water heaters.
14 RTF. ComDHWEfficientTank_v3_0.xlsm. 2014. Simple average of commercial style water heaters.
15 RTF. ComDHWShowerhead_v3_0.xlsm. 2013.16 RTF. ComSmartPlugPower_v3_1.xlsm. Updated incremental costs based on IPC research.
17 Idaho Power TRM prepared by ADM Associates, Inc. 2015. NEBs from water savings from RTF. ComDishwasher_v1_2.xlsm. 2012.
18 RTF. ComCookingCombinationOven_v2_0.xlsm. 2013.
19 RTF. ComCookingConvectionOven_v2_0.xlsm. Simple average of half and full-size ovens. 2013.
20 RTF. ComCookingFryer_v2_0.xlsm. 2013.21 RTF. ComCookingSteamer_v2_0.xlsm. 2013.
22 RTF. AgPotatoOnionShedVFD_v3_0.xlsm. IPC costs.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 68 Demand-Side Management 2016 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 69
Irrigation Efficiency Rewards
Segment: Irrigation2016 Program Results
Summary of Cost-Effectiveness Results
Test Benefit Cost Ratio
UC Test ................................................$11,753,203 $2,372,352 4.95
TRC Test ..............................................26,203,681 8,162,206 3.21
RIM Test ...............................................11,753,203 8,740,273 1.34
PCT .......................................................21,650,388 7,797,164 2.78
Cost Inputs Ref
Program Administration ...........................................................................$365,041
Program Incentives..................................................................................2,007,311 I
Total UC ..................................................................................................$2,372,352 P
Measure Equipment and Installation (Incremental Participant Cost).......$7,797,164 M
Net Benefit Inputs (NPV)Ref
Resource Savings
2016 Annual Gross Energy (kWh).............................15,673,513
NPV Cumulative Energy (kWh) .................................113,632,386 $11,753,203 S
10% Credit (Northwest Power Act)............................1,175,320
Total Electric Savings ..................................................$12,928,524 A
Participant Bill Savings
NPV Cumulative Participant Bill Savings ..................$6,367,920 B
Other Benefits
Non-Utility Rebates/Incentives ...................................$–NUI
NEBs ..........................................................................$13,275,157 NEB
Benefits and Costs Included in Each Test
UC Test ..............................................= S * NTG = P
TRC Test ............................................= (A + NUI + NEB) * NTG = P + ((M-I) * NTG)
RIM Test ............................................= S * NTG = P + (B * NTG)
PCT ...................................................= B + I + NUI + NEB = M
Assumptions for Levelized Calculations
Discount Rate
Nominal (WACC) ............................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .......................................................3.66%
Escalation Rate ...................................................................................................3.00%
Net-to-Gross (NTG) .............................................................................................100%
Minimum NTG Sensitivity ....................................................................................20%
Average Customer Segment Rate/kWh ..............................................................$0.058
Line Losses .........................................................................................................9.60%
Notes: Energy savings are combined for projects under the Custom and Menu program. Savings under each Custom project is unique and individually calculated and assessed. NEBs including yield, labor, and other benefits reported by the customer.
Green Rewind initiative is available to agricultural, commercial, and industrial customers. Agricultural motor rewinds are paid under Irrigation Efficiency Rewards, but the savings are not included in the program cost-effectiveness.
Green Rewind savings are included in the sector cost-effectiveness.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 70 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure
Namea Measure Descriptions Replacing
Measure
Unit End Use
Measure Life
(yrs)b
Annual
Gross Energy Savings
(kWh/yr)c
NPV Avoided
Costsd NEB
Gross Incremental Participant
Coste
Incentive/
Unit
Admin Cost
($/kWh)f UC Ratiog
TRC
Ratioh Sources
Nozzle Replacement New flow-control-type nozzles replacing existing brass
nozzles or worn out flow control nozzles of same flow rate or less
Brass nozzles or worn out flow
control nozzles of same flow rate or less
Unit IPC_Irrigation 4 40.60 $15.77 – $6.50 $1.50 $0.023 6.48 2.33 1
Nozzle Replacement New nozzles replacing existing worn nozzles of same flow rate or less
Worn nozzle of same flow rate or less
Unit IPC_Irrigation 4 40.60 $15.77 – $2.43 $0.25 $0.023 13.32 5.16 1
Sprinklers Rebuilt or new brass impact sprinklers Unit IPC_Irrigation 5 28.26 $13.63 – $14.13 $2.75 $0.023 4.01 1.01 1
Levelers Rebuilt or new wheel line levelers Unit IPC_Irrigation 5 41.76 $20.14 – $3.72 $0.75 $0.023 11.77 4.73 1
Sprinklers Center pivot/linear move: Install new sprinkler package on an existing system
Unit IPC_Irrigation 5 100.19 $48.32 – $29.26 $8.00 $0.023 4.69 1.68 1
Gasket
Replacement
New gaskets for hand lines,
wheel lines, or portable mainline
Unit IPC_Irrigation 5 170.00 $81.99 – $4.49 $1.00 $0.023 16.70 10.74 1
Drain
Replacement
New drains, hand lines, wheel
lines, or portable mainline
Unit IPC_Irrigation 5 176.25 $85.00 – $15.67 $3.00 $0.023 12.05 4.74 1
Hub Replacement New wheel line hubs Unit IPC_Irrigation 10 73.06 $66.76 – $57.30 $12.00 $0.023 4.88 1.25 1
New Goose
Necks
New goose neck with drop
tube or boomback
Outlet IPC_Irrigation 15 14.50 $18.51 – $4.78 $1.00 $0.023 13.88 3.98 1
Pipe Repair Cut and pipe press or weld repair of leaking hand lines,
wheel lines, and portable mainline
Joint IPC_Irrigation 8 84.48 $63.35 – $20.63 $8.00 $0.023 6.37 3.09 1
Gasket Replacement New center pivot base boot gasket Unit IPC_Irrigation 8 1,456.40 $1,092.17 – $286.50 $125.00 $0.023 6.89 3.75 1
a Available measures in the Irrigation Efficiency Rewards Menu Incentive Option. For the Custom Incentive Option, projects are thoroughly reviewed by Idaho Power staff.
b Average measure life.c Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
d Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.g UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)
h TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. AgIrrigationHardware_v3.xlsm. 2013. Weighted average of western Idaho, eastern Washington and Oregon, and eastern and southern Idaho.
Year: 2016 Program: Irrigation Efficiency Rewards Market Segment: Irrigation Program Type: Energy Efficiency
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2016 Annual Report Page 71
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing
Measure
Unit End Use
Measure
Life (yrs)a
Annual
Gross Energy Savings
(kWh/yr)b
NPV Avoided
Costsc NEB
Gross Incremental Participant
Costd
Incentive/
Unit
Admin Cost
($/kWh)e UC Ratiof
TRC
Ratiog Source
Green Motors Program Rewind:
Motor size 15 HP
Green Motors Program Rewind: Motor size 15 HP Standard rewind practice Motor IPC_Irrigation 18 317.00 $471.57 – $153.77 $30.00 $0.050 10.29 3.06 1
Green Motors Program Rewind:
Motor size 20 HP
Green Motors Program Rewind: Motor size 20 HP Standard rewind practice Motor IPC_Irrigation 18 425.00 $632.24 – $171.56 $40.00 $0.050 10.32 3.61 1
Green Motors Program Rewind: Motor size 25 HP
Green Motors Program Rewind: Motor size 25 HP Standard rewind practice Motor IPC_Irrigation 17 595.00 $844.72 – $196.01 $50.00 $0.050 10.59 4.12 1
Green Motors Program Rewind: Motor size 30 HP
Green Motors Program Rewind: Motor size 30 HP Standard rewind practice Motor IPC_Irrigation 17 640.00 $908.60 – $215.29 $60.00 $0.050 9.88 4.04 1
Green Motors Program Rewind: Motor size 40 HP
Green Motors Program Rewind: Motor size 40 HP Standard rewind practice Motor IPC_Irrigation 17 746.00 $1,059.09 – $263.09 $80.00 $0.050 9.03 3.88 1
Green Motors
Program Rewind: Motor size 50 HP
Green Motors Program
Rewind: Motor size 50 HP
Standard rewind
practice
Motor IPC_Irrigation 17 802.00 $1,138.59 – $291.24 $100.00 $0.050 8.13 3.78 1
Green Motors
Program Rewind: Motor size 60 HP
Green Motors Program
Rewind: Motor size 60 HP
Standard rewind
practice
Motor IPC_Irrigation 20 765.00 $1,235.55 – $343.49 $120.00 $0.050 7.81 3.56 1
Green Motors
Program Rewind: Motor size 75 HP
Green Motors Program
Rewind: Motor size 75 HP
Standard rewind
practice
Motor IPC_Irrigation 20 788.00 $1,272.70 – $371.28 $150.00 $0.050 6.72 3.41 1
Green Motors Program Rewind: Motor size 100 HP
Green Motors Program Rewind: Motor size 100 HP Standard rewind practice Motor IPC_Irrigation 20 1,040.00 $1,679.71 – $460.58 $200.00 $0.050 6.67 3.60 1
Green Motors Program Rewind:
Motor size 125 HP
Green Motors Program Rewind: Motor size 125 HP Standard rewind practice Motor IPC_Irrigation 20 1,157.00 $1,868.67 – $517.27 $250.00 $0.050 6.07 3.57 1
Green Motors Program Rewind:
Motor size 150 HP
Green Motors Program Rewind: Motor size 150 HP Standard rewind practice Motor IPC_Irrigation 20 1,376.00 $2,222.38 – $576.19 $300.00 $0.050 6.03 3.79 1
Green Motors Program Rewind:
Motor size 200 HP
Green Motors Program Rewind: Motor size 200 HP Standard rewind practice Motor IPC_Irrigation 20 1,821.00 $2,941.10 – $693.65 $400.00 $0.050 5.99 4.12 1
Green Motors Program Rewind: Motor size 250 HP
Green Motors Program Rewind: Motor size 250 HP Standard rewind practice Motor IPC_Irrigation 20 2,823.00 $4,559.44 – $891.52 $500.00 $0.050 7.11 4.86 1
Green Motors Program Rewind: Motor size 300 HP
Green Motors Program Rewind: Motor size 300 HP Standard rewind practice Motor IPC_Irrigation 20 3,370.00 $5,442.90 – $901.16 $600.00 $0.050 7.08 5.60 1
Green Motors
Program Rewind: Motor size 350 HP
Green Motors Program
Rewind: Motor size 350 HP
Standard rewind
practice
Motor IPC_Irrigation 20 3,929.00 $6,345.74 – $944.51 $700.00 $0.050 7.08 6.12 1
Year: 2016 Program: Irrigation Efficiency Rewards—Green Motors Market Segment: Irrigation Program Type: Energy Efficiency
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 72 Demand-Side Management 2016 Annual Report
Benefit Cost B/C Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use Measure Life (yrs)a
Annual
Gross Energy
Savings (kWh/yr)b
NPV
Avoided Costsc NEB
Gross Incremental
Participant Costd
Incentive/ Unit
Admin
Cost ($/kWh)e UC Ratiof
TRC Ratiog Source
Green Motors Program Rewind: Motor size 400 HP
Green Motors Program Rewind: Motor size 400 HP Standard rewind practice Motor IPC_Irrigation 20 4,456.00 $7,196.90 – $1,054.93 $800.00 $0.050 7.04 6.20 1
Green Motors Program Rewind:
Motor size 450 HP
Green Motors Program Rewind: Motor size 450 HP Standard rewind practice Motor IPC_Irrigation 20 5,003.00 $8,080.36 – $1,153.12 $900.00 $0.050 7.03 6.33 1
Green Motors Program Rewind:
Motor size 500 HP
Green Motors Program Rewind: Motor size 500 HP Standard rewind practice Motor IPC_Irrigation 20 5,567.00 $8,991.28 – $1,245.76 $1,000.00 $0.050 7.03 6.49 1
Green Motors Program Rewind:
Motor size 600 HP
Green Motors Program Rewind: Motor size 600 HP Standard rewind practice Motor IPC_Irrigation 20 6,193.00 $10,002.33 – $1,835.78 $1,200.00 $0.050 6.63 5.13 1
Green Motors Program Rewind: Motor size 700 HP
Green Motors Program Rewind: Motor size 700 HP Standard rewind practice Motor IPC_Irrigation 20 7,195.00 $11,620.67 – $2,002.84 $1,400.00 $0.050 6.60 5.41 1
Green Motors Program Rewind: Motor size 800 HP
Green Motors Program Rewind: Motor size 800 HP Standard rewind practice Motor IPC_Irrigation 20 8,205.00 $13,251.92 – $2,222.20 $1,600.00 $0.050 6.59 5.54 1
Green Motors Program Rewind: Motor size 900 HP
Green Motors Program Rewind: Motor size 900 HP Standard rewind practice Motor IPC_Irrigation 20 9,211.00 $14,876.71 – $2,449.87 $1,800.00 $0.050 6.58 5.62 1
Green Motors
Program Rewind: Motor size
1,500 HP
Green Motors Program
Rewind: Motor size 1,500 HP
Standard rewind
practice
Motor IPC_Irrigation 20 12,681.00 $20,481.12 – $3,612.90 $3,000.00 $0.050 4.51 4.37 1
a Average measure life.b Estimated kWh savings measured at the customer’s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2013 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act.
d Incremental participant cost prior to customer incentives.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2016 actuals.f UC Ratio = (NPV Avoided Costs) / ((Admin Cost/kWh * kWh Savings) + Incentives)g TRC Ratio = ((NPV Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. AgMotorsRewind_v2_0.xlsm. 2013.