Supplement 1: Cost-Effectiveness - Idaho Power · 2017. 3. 14. · Cost Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers;

2016Annual Report

MARCH 15 • 2017

DEMAND -SIDE MANAGEMENT

SUPPLEMENT 1: COST-EFFECTIVENESS

Printed on recycled paper

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


Demand-Side Management 2016 Annual Report Page 1

supplemenT 1: CosT-effeCTiveness

Cost-EffectivenessIdaho 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.


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.

MethodologyFor 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.



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.

AssumptionsIdaho 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,



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



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 AdderThe 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 nonconservation 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.



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-GrossNet-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.

ResultsIdaho 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.



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



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

ProgramNumber 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



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 ProgramIncluded 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 ProgramEnergy Efficiency/Demand ResponseResidentialA/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



Table 2. 2016 DSM detailed expenses by program (dollars) (continued)

Sector/Program Idaho Rider Oregon Rider Idaho Power Total ProgramFridge 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




Sector/Program Idaho Rider Oregon Rider Idaho Power Total ProgramCommercial/IndustrialNew 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 IrrigationIrrigation 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 TransformationNEAA ....................................................................... 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




Sector/Program Idaho Rider Oregon Rider Idaho Power Total ProgramOther Programs and ActivitiesResidential 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 ExpensesCommercial/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



Table 3. Cost-effectiveness of 2016 programs by B/C test

Program/Sector UC TRC RIM PCTEasy 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.



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CosT-effeCTiveness Tables by program

Easy SavingsSegment: Residential2016 Program Results

Summary of Cost-Effectiveness ResultsTest 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 RefProgram Administration .......................................................................... $ 127,587

Program Incentives................................................................................. – I

Total UC ................................................................................................. $ 127,587 P

Measure Equipment and Installation (Incremental Participant Cost)...... $ – M

Net Benefit Inputs (NPV) RefResource 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 BenefitsNon-Utility Rebates/Incentives ......................................... $ – NUI

NEBs ................................................................................ $ 23,712 NEB

Benefits and Costs Included in Each TestUC 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 CalculationsDiscount 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.






Education DistributionsSegment: Residential2016 Program Results


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 RefProgram Administration .......................................................................... $ 2,392,884


Total UC ................................................................................................. $ 2,392,884 P



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


NPV Cumulative Participant Bill Savings ............... $ 10,892,667 B

Other BenefitsNon-Utility Rebates/Incentives ................................ $ – NUI

NEBs ....................................................................... $ 5,591,894 NEB


TRC Test .............................................. = (A + NUI + NEB) * NTG = P


PCT ..................................................... N/A N/A


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.



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

CostdIncentive/

Unit

Admin Cost

($/kWh)e UC RatiofTRC

Ratiog SourceGeneral 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



Energy Efficient LightingSegment: Residential2016 Program Results


Program Incentives................................................................................. 2,134,864 I

Total UC ................................................................................................. $ 3,080,708 P

Measure Equipment and Installation (Incremental Participant Cost) $ 9,821,995 M


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


NPV Cumulative Participant Bill Savings ............. $ 16,404,560 B

Other BenefitsNon-Utility Rebates/Incentives .............................. $ – NUI

NEBs ..................................................................... $ 12,642,707 NEB


TRC Test .............................................. = (A + NUI + NEB) * NTG = P + ((M-I) * NTG)


PCT ..................................................... = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%

Note: NEBs include PV of periodic bulb (capital) replacement costs.


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






Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceDecorative 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


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



Efficient Technology: Compact fluorescent Lamp Type: General purpose and dimmable Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb



Efficient Technology: Compact fluorescent Lamp Type: General purpose and dimmable Lumen Category: 1,440 to 2,600 lumens Space Type: Any

Baseline bulb


Globe CFL Retailer

Efficient Technology: Compact fluorescent Lamp Type: Globe Lumen Category: 250 to 664 lumens Space Type: Any

Baseline bulb


Year: 2016 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency






Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceGlobe CFL Retailer

Efficient Technology: Compact fluorescent Lamp Type: Globe Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb


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



Efficient Technology: Compact fluorescent Lamp Type: Reflectors and outdoor Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb



Efficient Technology: Compact fluorescent Lamp Type: Reflectors and outdoor Lumen Category: 1,440 to 2,600 lumens Space Type: Any

Baseline bulb


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


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


General Purpose LED Retailer

Efficient Technology: LED Lamp Type: General purpose and dimmable Lumen Category: 250 to 664 lumens Space Type: Any

Baseline bulb







Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceGeneral Purpose LED Retailer

Efficient Technology: LED Lamp Type: General purpose and dimmable Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb



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


Globe LED Retailer

Efficient Technology: LED Lamp Type: Globe Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb


Reflectors and Outdoor LED Retailer

Efficient Technology: LED Lamp Type: Reflectors and outdoor Lumen Category: 250 to 664 lumens Space Type: Any

Baseline bulb



Efficient Technology: LED Lamp Type: Reflectors and outdoor Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb



Efficient Technology: LED Lamp Type: Reflectors and outdoor Lumen Category: 1,440 to 2,600 lumens Space Type: Any

Baseline bulb


Three-Way LED Retailer

Efficient Technology: LED Lamp Type: Three-way Lumen Category: 665 to 1,439 lumens Space Type: Any

Baseline bulb


Three-Way LED Retailer

Efficient Technology: LED Lamp Type: Three-way Lumen Category: 1,440 to 2,600 lumens Space Type: Any

Baseline bulb







Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceCFL 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


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.






Energy House CallsSegment: Residential2016 Program Results


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



Total UC ................................................................................................. $ 206,437 P










NEBs ................................................................................ $ 88,003 NEB

Benefits and Costs Included in Each TestUC Test ............................................. = S * NTG = P

TRC Test ........................................... = (A + NUI + NEB) * NTG = P

RIM Test ........................................... = S * NTG = P + (B * NTG)

PCT .................................................. N/A N/A


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourcePTCS 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


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



PTCS Duct Sealing

Manufactured Home Prescriptive Duct Sealing—Heat Pump—Heating Zone 2 or 3



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



Showerhead ENRes_SF_WtrHtr 10 222.00 $127.50 $172.11 – – $0.405 1.42 3.47 4


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



ENERGY STAR® Homes NorthwestSegment: Residential2016 Program Results


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


Program Incentives................................................................................. 110,000 I

Total UC ................................................................................................. $ 142,158 P

Measure Equipment and Installation (Incremental Participant Cost)...... $ 265,360 M


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


NPV Cumulative Participant Savings .......................... $ 259,743 B

Other BenefitsNon-Utility Rebates/Incentives .................................... $ – NUI

NEBs ........................................................................... $ 16,643 NEB

Benefits and Costs Included in Each TestUC 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


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.






Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceENERGY 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



Fridge and Freezer Recycling Program (See ya later, refrigerator®)Segment: Residential2016 Program Results


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



Total UC ................................................................................................. $ 257,916 P




NPV Cumulative Energy (kWh) ................................... 3,646,797 $ 236,992 S


Total Electric Savings .................................................... $ 260,691 A


NPV Cumulative Participant Bill Savings .................... $ 292,051 B


NEBs ........................................................................... $ 75,991 NEB


TRC Test ............................................ = (A + NUI + NEB) * NTG = P


PCT ................................................... N/A = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%

Notes: Program re-launched on June 1, 2016. No participant cost.






Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceFreezer 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



Heating & Cooling Efficiency ProgramSegment: Residential2016 Program Results


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 RefProgram Administration ........................................................................... $ 365,738

Program Incentives.................................................................................. 229,175 I

Total UC .................................................................................................. $ 594,913 P

Measure Equipment and Installation (Incremental Participant Cost)....... $ 1,038,887 M


2016 Annual Gross Energy (kWh)............................... 1,113,574

NPV Cumulative Energy (kWh) ................................... 14,484,058 $ 1,387,634 S


Total Electric Savings .................................................... $ 1,526,397 A


NPV Cumulative Participant Bill Savings .................... $ 1,359,564 B

Other BenefitsNon-Utility Rebates/Incentives ..................................... $ – NUI

NEBs ............................................................................ $ 241,161 NEB


TRC Test ........................................... = (A + NUI + NEB) * NTG = P + ((M-I) * NTG)


PCT .................................................. = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%

Note: NEBs include NPV of RTF values for annual operation and maintenance (O&M) savings and monetized comfort savings.






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceHeat 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.


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






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceWhole 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


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.






Home Improvement ProgramSegment: Residential2016 Program Results


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



Total UC .................................................................................................. $ 324,024 P



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


NPV Cumulative Participant Bill Savings ..................... $ 954,935 B

Other BenefitsNon-Utility Rebates/Incentives ..................................... $ – NUI

NEBs ............................................................................ $ 107,582 NEB




PCT ................................................... = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%

Minimum NTG Sensitivity .................................................................................... N/A


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.






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceMulti 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


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



Multifamily Energy Savings ProgramSegment: Residential2016 Program Results


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


Program Incentives.................................................................................. – I

Total UC .................................................................................................. $ 59,046 P

Measure Equipment and Installation (Incremental Participant Cost)....... $ – M









NEBs ................................................................................ $ 57,879 NEB




PCT ................................................... N/A N/A


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%



Year: 2016 Program: Multifamily Energy Savings Program Market Segment: Residential Program Type: Energy Efficiency




Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog Source




12 11.00 $7.41 $4.00 – – $0.394 1.71 2.80 1, 2

General Purpose LED Direct Install



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


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


12 12.00 $8.08 $16.87 – – $0.394 1.71 5.45 1

Low-Flow Showerheads Direct Install



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


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.



Rebate AdvantageSegment: Residential2016 Program Results


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



Total UC .................................................................................................. $ 111,050 P

Measure Equipment and Installation (Incremental Participant Cost)....... $ 103,092 M









NEBs ................................................................................ $ 18,026 NEB

Benefits and Costs Included in Each TestUC 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


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%



Year: 2016 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency


Measure Name

Measure Descriptions Replacing


Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost

($/kWh)eUC

RatiofTRC

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


Manufactured home built to HUD code







New Energy Star Manufactured Home with Heat Pump—Heating Zone 1 Cooling Zone 3


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





25 4,346.00 $6,424.51 $264.04 $1,577.57 $1,000.00 $0.110 4.35 3.57 1





25 4,390.00 $6,489.55 $264.04 $1,577.57 $1,000.00 $0.110 4.38 3.59 1





25 4,472.00 $6,610.77 $264.04 $1,577.57 $1,000.00 $0.110 4.43 3.64 1





26 5,516.00 $8,381.93 $270.44 $1,577.57 $1,000.00 $0.110 5.22 4.34 1


New EcoRated Manufactured Home with Electric FAF—Heating Zone 1



26 5,691.00 $8,647.85 $270.44 $1,993.00 $1,000.00 $0.110 5.32 3.74 1


New EcoRated Manufactured Home with Electric FAF—Heating Zone 2



27 7,438.00 $11,598.01 $276.61 $1,993.00 $1,000.00 $0.110 6.38 4.64 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 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.






Simple Steps, Smart Savings™

Segment: Residential2016 Program Results


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



Total UC .................................................................................................. $ 153,784 P

Measure Equipment and Installation (Incremental Participant Cost)....... $ 286,809 M









NEBs ................................................................................ $ 101,379 NEB




PCT ................................................... = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%

Note: NEBs include the NPV of water savings from low-flow showerheads and clothes washers.






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceClothes 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





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



Weatherization Assistance for Qualified CustomersSegment: Residential2016 Program Results


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


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



NPV Cumulative Energy (kWh) ................................... 10,709,122 $ 994,297 S


Total Electric Savings .................................................... $ 1,093,726 A


NPV Cumulative Participant Bill Savings .................... $ 1,053,412 B


NEBs ...........................................................................

Health and Safety .................................................. $ 185,571

Repair .................................................................... $ 27,432

Other ...................................................................... –

NEBs Total .................................................................. $ 213,003 NEB

Benefits and Costs Included in Each TestUC 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


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.






Weatherization Solutions for Eligible CustomersSegment: Residential2016 Program Results


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


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









NEBs ................................................................................

Health and Safety ....................................................... 47,109

Repair ......................................................................... 12,109

Other ........................................................................... –

NEBs Total ....................................................................... $ 59,218 NEB

Benefits and Costs Included in Each TestUC 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


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.






New Construction (Building Efficiency)Segment: Commercial2016 Program Results


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


Program Incentives.................................................................................. 1,516,161 I

Total UC .................................................................................................. $ 1,931,222 P



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


NPV Cumulative Participant Bill Savings ................ $ 6,881,170 B


NEBs ....................................................................... $ – NEB




PCT .................................................. = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%




Measure Name Measure Descriptions ReplacingMeasure Unit End Use

Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost

($/kWh)eUC

RatiofTRC

Ratiog SourceLighting 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.


Lighting Interior light load reduction. Part C: Equal to or greater than 30% below code.


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, 2Lighting Occupancy sensors Code standards Sensor ENComm_InsLt 8 366.00 $190.08 – $38.26 $25.00 $0.039 4.84 3.98 1Lighting High-efficiency exit signs Code standards Sign IPC_8760 16 28.00 $24.67 – $10.83 $7.50 $0.039 2.87 2.28 1A/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)


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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost

($/kWh)eUC

RatiofTRC

Ratiog SourceA/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)


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)


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)


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)


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)


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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost

($/kWh)eUC

RatiofTRC

Ratiog SourceA/C Air-cooled chiller condenser,

IPLV 14.0 EER or higherCode 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


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


A/C Direct evaporative cooler IECC 2012


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 1Controls 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


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


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


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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost

($/kWh)eUC

RatiofTRC

Ratiog SourceVariable-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


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


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


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


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.






Custom Projects (Custom Efficiency)Segment: Industrial2016 Program Results


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 RefProgram 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


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


NPV Cumulative Participant Savings ...................... $ 21,213,258 B


NEBs ....................................................................... $ – NEB




PCT ................................................... = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.




Measure NameMeasure Descriptions Replacing


Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceGreen 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




Motor MF_Motors 8 804.00 $402.86 – $171.56 $40.00 $0.050 5.02 2.09 1




Motor MF_Motors 8 1,052.00 $527.13 – $196.01 $50.00 $0.050 5.14 2.33 1




Motor MF_Motors 8 1,133.00 $567.71 – $215.29 $60.00 $0.050 4.87 2.30 1




Motor MF_Motors 8 1,319.00 $660.91 – $263.09 $80.00 $0.050 4.53 2.21 1




Motor MF_Motors 8 1,418.00 $710.52 – $291.24 $100.00 $0.050 4.16 2.16 1




Motor MF_Motors 9 1,476.00 $825.50 – $343.49 $120.00 $0.050 4.26 2.18 1




Motor MF_Motors 9 1,519.00 $849.55 – $371.28 $150.00 $0.050 3.76 2.09 1




Motor MF_Motors 9 2,005.00 $1,121.36 – $460.58 $200.00 $0.050 3.73 2.20 1




Motor MF_Motors 8 2,598.00 $1,301.78 – $517.27 $250.00 $0.050 3.43 2.21 1




Motor MF_Motors 8 3,089.00 $1,547.80 – $576.19 $300.00 $0.050 3.41 2.33 1




Motor MF_Motors 8 4,088.00 $2,048.37 – $693.65 $400.00 $0.050 3.39 2.51 1




Motor MF_Motors 9 4,972.00 $2,780.75 – $891.52 $500.00 $0.050 3.71 2.68 1




Motor MF_Motors 9 5,935.00 $3,319.34 – $901.16 $600.00 $0.050 3.70 3.05 1




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




Measure NameMeasure Descriptions Replacing


Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost





Motor MF_Motors 9 7,848.00 $4,389.25 – $1,054.93 $800.00 $0.050 3.68 3.34 1




Motor MF_Motors 9 8,811.00 $4,927.84 – $1,153.12 $900.00 $0.050 3.68 3.40 1




Motor MF_Motors 9 9,804.00 $5,483.21 – $1,245.76 $1,000.00 $0.050 3.68 3.47 1




Motor MF_Motors 7 14,689.00 $6,474.07 – $1,835.78 $1,200.00 $0.050 3.35 2.77 1




Motor MF_Motors 7 17,065.00 $7,521.27 – $2,002.84 $1,400.00 $0.050 3.34 2.90 1




Motor MF_Motors 7 19,461.00 $8,577.29 – $2,222.20 $1,600.00 $0.050 3.33 2.95 1




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



Motor MF_Motors 7 35,891.00 $15,818.69 – $3,612.90 $3,000.00 $0.050 2.28 2.30 1




Motor MF_Motors 7 70,147.00 $30,916.76 – $6,446.18 $6,000.00 $0.050 2.24 2.39 1


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.






Retrofits (Easy Upgrades)Segment: Commercial2016 Program Results


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 RefProgram Administration ........................................................................... $ 1,152,228


Total UC .................................................................................................. $ 5,040,190 P



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


NPV Cumulative Participant Savings ......................... $ 15,615,872 B

Other BenefitsNon-Utility Rebates/Incentives ................................... $ – NUI

NEBs .......................................................................... $ – NEB




PCT .................................................. = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



Line Losses ......................................................................................................... 9.60%

Note: Measure inputs from Evergreen Consulting Group or the TRM prepared by ADM Associates, Inc., unless otherwise noted.




Measure Name Measure Descriptions ReplacingMeasure unit End Use

Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceStandard/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




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


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


Screw-in CFLs/cold-cathode


Fixture using >40 input watts


Hardwired CFLs Hardwired CFLs Fixture using >90 input watts


LED Replacement Lamps

LED replacement lamps Fixture using >20 input watts


Pulse Start/Electronic Metal Halide

Pulse start/electronic metal halide


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





Year: 2016 Program: Retrofits Market Segment: Commercial Program Type: Energy Efficiency





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceStandard/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


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







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


LED Replacement Lamps

LED Replacement Lamps Fixture using >20 input watts






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


Case # 2—LED display case lighting (per linear foot)


Linear foot ENComm_Refrigeration

8 111.25 $55.52 $17.21 $42.56 $15.00 $0.039 2.87 1.67 3


Case # 3—LED display case lighting (per linear foot)



8 77.75 $38.80 $15.95 $44.21 $10.00 $0.039 2.98 1.24 4


Case #4—TLED display case lighting



12 34.49 $24.84 $2.48 $8.48 $1.50 $0.039 8.73 3.03 5


Case #5—TLED display case lighting



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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceA/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)



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)


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)


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


Chillers Water-cooled chiller electronically operated, reciprocating and positive displacement

Standard water-cooled chiller


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






Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceAutomated 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



Tons of cooling

ENComm_Cooling 15 794.00 $916.22 – $197.98 $150.00 $0.039 5.06 4.40 11

Automated Controls



Tons of cooling

ENComm_Cooling 15 794.00 $916.22 – $197.98 $175.00 $0.039 4.45 4.40 9

Automated Controls



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


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



Tons of cooling

ENComm_Cooling 15 484.00 $558.50 – $162.49 $80.00 $0.039 5.65 3.39 11

Automated Controls



Tons of cooling

ENComm_Cooling 15 484.00 $558.50 – $162.49 $90.00 $0.039 5.13 3.39 9

Automated Controls



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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceLaundry 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


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


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


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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceStandby 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


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


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


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


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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceCommercial 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


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


ENERGY STAR listed electric combination oven (15–20 pans)


Oven ENComm_Cooking 10 17,877.00 $11,372.62 – $446.11 $300.00 $0.039 11.41 10.95 18


ENERGY STAR listed electric convection oven


Oven ENComm_Cooking 10 1,672.00 $1,063.66 – $923.04 $300.00 $0.039 2.91 1.18 19


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


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






Standard steamer Steamer ENComm_Cooking 9 35,659.00 $20,610.31 – $(270.07) $150.00 $0.039 13.39 20.25 21





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





Measure Life

(yrs)a




CostdIncentive/

Unit

Admin Cost


Ratiog SourceVariable-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


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.






Irrigation Efficiency RewardsSegment: Irrigation2016 Program Results


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



Total UC .................................................................................................. $ 2,372,352 P



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


NPV Cumulative Participant Bill Savings .................. $ 6,367,920 B

Other BenefitsNon-Utility Rebates/Incentives ................................... $ – NUI

NEBs .......................................................................... $ 13,275,157 NEB




PCT ................................................... = B + I + NUI + NEB = M


Nominal (WACC) ............................................................................................ 6.77%


Escalation Rate ................................................................................................... 3.00%

Net-to-Gross (NTG) ............................................................................................. 100%



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.




Measure Namea Measure Descriptions Replacing


Measure Life

(yrs)b

Annual Gross Energy Savings (kWh/yr)c

NPV Avoided Costsd NEB


CosteIncentive/

Unit

Admin Cost

($/kWh)f UC RatiogTRC

Ratioh SourcesNozzle 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


Sprinklers Rebuilt or new brass impact sprinklers


Levelers Rebuilt or new wheel line levelers


Sprinklers Center pivot/linear move: Install new sprinkler package on an existing system


Gasket Replacement

New gaskets for hand lines, wheel lines, or portable mainline


Drain Replacement

New drains, hand lines, wheel lines, or portable mainline


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





Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost





Motor IPC_Irrigation 18 317.00 $471.57 – $153.77 $30.00 $0.050 10.29 3.06 1
















Motor IPC_Irrigation 17 746.00 $1,059.09 – $263.09 $80.00 $0.050 9.03 3.88 1
















Motor IPC_Irrigation 20 1,040.00 $1,679.71 – $460.58 $200.00 $0.050 6.67 3.60 1

























Year: 2016 Program: Irrigation Efficiency Rewards—Green Motors Market Segment: Irrigation Program Type: Energy Efficiency





Measure Life (yrs)a




CostdIncentive/

Unit

Admin Cost





Motor IPC_Irrigation 20 4,456.00 $7,196.90 – $1,054.93 $800.00 $0.050 7.04 6.20 1




Motor IPC_Irrigation 20 5,003.00 $8,080.36 – $1,153.12 $900.00 $0.050 7.03 6.33 1




Motor IPC_Irrigation 20 5,567.00 $8,991.28 – $1,245.76 $1,000.00 $0.050 7.03 6.49 1






















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.

Documents

Supplement 1: Cost-Effectiveness - Idaho Power · 2017. 3. 14. · Cost Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers;