2017 Annual Report SUPPLEMENT 1: COST-EFFECTIVENESS DEMAND-SIDE MANAGEMENT

Transcription

1 2017 Annual Report SUPPLEMENT 1: COST-EFFECTIVENESS DEMAND-SIDE MANAGEMENT MARCH

2 Printed on recycled paper

3 Idaho Power Company Supplement 1: Cost-Effectiveness Table of Contents Supplement 1: Cost-Effectiveness...1 Cost-Effectiveness...1 Methodology...2 Assumptions...3 Conservation Adder...6 Net-to-...6 Results DSM Detailed Expenses by Program...11 Cost-Effectiveness Tables by Program...16 Educational Distributions...16 Energy Efficient Lighting...18 Energy House Calls...21 Fridge and Freezer Recycling Program...23 Heating & Cooling Efficiency Program...25 Home Improvement Program...28 Multifamily Energy Savings Program...30 Rebate Advantage...33 Residential New Construction Pilot Program (ENERGY STAR Homes Northwest)...35 Simple Steps, Smart Savings...37 Weatherization Assistance for Qualified Customers...39 Weatherization Solutions for Eligible Customers...40 Custom Projects...41 New Construction...44 Retrofits...49 Irrigation Efficiency Rewards...58 Demand-Side Management 2017 Annual Report Page i

4 Supplement 1: Cost-Effectiveness Idaho Power Company List of Tables Table non-cost-effective measures...10 Table DSM detailed expenses by program (dollars)...11 Table 3. Cost-effectiveness of 2017 programs by B/C test...15 Page ii Demand-Side Management 2017 Annual Report

5 Idaho Power Company Supplement 1: Cost-Effectiveness Cost-Effectiveness Supplement 1: Cost-Effectiveness Idaho Power considers cost-effectiveness of primary importance in the design, implementation, and tracking of energy efficiency and demand response programs. Idaho Power s energy efficiency and demand response opportunities are preliminarily identified through the Integrated Resource Plan (IRP) process. Idaho Power uses third-party energy efficiency potential studies to identify achievable cost effective energy efficiency potential, which is added to the resources included in the IRP. Idaho Power s Program Planning Group (PPG) explores new opportunities to expand current demand side management (DSM) programs and offerings. Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power performs a preliminary cost-effectiveness analysis to assess whether a potential program design or measure may be cost-effective from the perspective of Idaho Power and its customers. Incorporated in these models are inputs from various sources that use the most current and reliable information available. When possible, Idaho Power leverages the experiences of other utilities in the region and/or throughout the country to help identify specific program parameters. This is accomplished through discussions with other utilities program managers and researchers. Idaho Power also uses electric industry research organizations, such as E Source, NEEA Regional Emerging Technology Advisory Committee, the Consortium for Energy Efficiency (CEE), American Council for an Energy Efficient Economy (ACEEE), Advanced Load Control Alliance (ALCA), and Association of Energy Service Professionals (AESP) to compare similar programs and their results. Additionally, Idaho Power relies on the results of program impact evaluations and recommendations from consultants. Idaho Power s objective is for all programs to have benefit/cost (B/C) ratios greater than 1.0 for the total resource cost (TRC) test, utility cost (UC) test, and participant cost test (PCT) at the program and measure level where appropriate. Each cost-effectiveness test provides a different perspective, and Idaho Power believes each test provides value when evaluating program performance. If a measure or program is found to be not cost-effective from one or more of the three tests, Idaho Power assesses it and runs the cost-effectiveness calculations under a variety of scenarios and assumptions. For some measures within the programs, savings can vary based on factors such participation levels or the participants locations. For instance, heat pumps installed in the Boise area will have less savings than heat pumps installed in the McCall area. If program participation and savings increase, fixed costs such as labor and marketing are spread out more and the program cost-effectiveness increases. When a program or measure is shown to be not cost-effective, Idaho Power works with the Energy Efficiency Advisory Group (EEAG) to get additional input. If the measure or program is indeed offered, the company explains to stakeholders why the measure or program was implemented or continued and what steps the company plans to take to improve its cost-effectiveness. The company believes this aligns with the expectations of the Idaho Public Utilities Commission (IPUC) and Public Utility Commission of Oregon (OPUC). Demand-Side Management 2017 Annual Report Page 1

6 Supplement 1: Cost-Effectiveness Idaho Power Company In IPUC Order No , page 9, the IPUC states the following: We thus find it reasonable for the Company to continue screening potential programs using each test as a guideline, and to advise us on how the Company s programs fare under each test. When the Company ultimately seeks to recover its prudent investment in such programs, however, we believe the Company may (but need not exclusively) emphasize the UCT and that test s focus on Company-controlled benefits and costs to argue whether the programs were cost-effective. In the OPUC Order No , 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. s 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 : 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 , 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 its Oregon and Idaho jurisdictions for a variety of reasons. Some customers, contractors, and trade allies operate in both states. Program consistency is important for the participants overall satisfaction with the programs. Offering different program designs would create confusion in the marketplace and could inhibit participation. In addition, program infrastructure is designed to implement consistent programs across the service area. Methodology For its cost-effectiveness methodology, Idaho Power relies on the Electric Power Research Institute (EPRI) End Use Technical Assessment Guide (TAG); the California Standard Practice Manual and its subsequent addendum, the National Action Plan for Energy Efficiency s (NAPEE) Understanding Page 2 Demand-Side Management 2017 Annual Report

7 Idaho Power Company Supplement 1: Cost-Effectiveness 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 primarily uses the TRC test. This test is used because, as defined in the TAG and California Standard Practice Manual, it is the most similar to supply-side tests, and it provides a useful basis to compare demand-side and supply-side resources. For program planning and evaluation the company primarily uses the TRC and the UC test to develop B/C ratios to determine the cost-effectiveness of DSM programs. The PCT provides the company the opportunity to assess a program or measure from the participant perspective and to determine if it is in the best interest of the average customer. For energy efficiency programs, each program s cost-effectiveness is reviewed annually from a one-year perspective. The annual energy-savings benefit value is summed over the life of the measure or program and is discounted to reflect 2017 dollars. The result of the one-year perspective is shown in Supplement 1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2017 Annual Report includes the program cost-effectiveness to date by including the culmination of actual historic savings values and expenses, as well as the ongoing energy-savings benefit over the life of the measures included in a program. The goal of demand response programs is to minimize or delay the need to build new supply-side resources. Unlike energy efficiency programs or supply-side resources, demand response programs must acquire and retain participants each year to maintain a level of demand-reduction capacity for the company. As part of the public workshops on Case No. IPC-E-13-14, Idaho Power and other stakeholders agreed on a new methodology for valuing demand response. The settlement agreement, as approved in IPUC Order No and OPUC Order No , defined the annual cost of operating the three demand response programs for the maximum allowable 60 hours to be no more than $16.7 million. The annual value calculation will be updated with each IRP based on changes that include, but are not limited to, need, capital cost, or financial assumptions. This amount was reevaluated in the 2015 IRP to be $18.5 million. This $18.5 million value is the levelized annual cost of a 170-megawatt (MW) deferred resource over a 20-year life. The demand response value calculation will include this value even in years when the IRP shows no peak-hour capacity deficits. In 2017, the cost of operating the three demand response programs was $8.8 million. Idaho Power estimates that if the three programs were dispatched for the full 60 hours, the total costs would have been approximately $11.1 million and would have remained cost-effective. Assumptions Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumptions for various measures. These assumptions are routinely reviewed internally and with EEAG and updated as new information becomes available. For many of the measures within Supplement 1: Cost Effectiveness, savings and costs were derived from either the Regional Technical Forum (RTF) or the Idaho Power Energy Efficiency Potential Study conducted by Applied Energy Group (AEG) in Demand-Side Management 2017 Annual Report Page 3

8 Supplement 1: Cost-Effectiveness Idaho Power Company Idaho Power received end-use load shapes from AEG which have been applied to each program and measure when applicable. AEG refreshed the energy efficiency potential analysis in Due to the timing of the 2016 potential study, Idaho Power will use any updated assumptions from the 2016 potential study for the 2018 cost-effectiveness analyses. The RTF regularly reviews, evaluates, and recommends eligible energy efficiency measures and the estimated savings and costs associated with those measures. For instance, because of the rapid changes in the lighting market, the RTF currently evaluates lighting measures annually. As the RTF updates these assumptions, Idaho Power applies them to current program offerings and assesses the need to make any program changes. Idaho Power 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 2017 dollars. For workbooks still in 2006 dollars, the costs are escalated by 19.6 percent. For workbooks in 2012 dollars, the costs are escalated by 7.8 percent. This percentage is provided by the RTF in workbook RTFStandardInformationWorkbook_ v3_1.xlsx. Idaho Power uses a technical reference manual (TRM) developed by ADM Associates, Inc., for the Commercial and Industrial Energy Efficiency Program s New Construction and Retrofit options. In 2017, the company has contracted with ADM to update the TRM in preparation for changes that will be made to the program in Idaho Power also relies on other sources, such as the Northwest Power and Conservation Council (NWPCC), Northwest Energy Efficiency Alliance (NEEA), the Database for Energy Efficiency Resources (DEER), the Energy Trust of Oregon (ETO), the Bonneville Power Administration (BPA), third-party consultants, and other regional utilities. Occasionally, Idaho Power will also use internal engineering estimates and calculations for savings and costs based on information gathered from previous projects. The company freezes savings assumptions when the budgets are established for the next calendar year unless code and standard changes or program updates necessitate a need to use updated savings. As a general rule, the 2017 energy savings reported for most programs will use the assumption set at the beginning of the program year. These assumptions are discussed in more detail in the cost-effectiveness sections for each program. The remaining inputs used in the cost-effectiveness models are obtained from the IRP process. Idaho Power s 2015 IRP was acknowledged by the IPUC on December 23, 2015 and by the OPUC April 28, 2016 and is the source of all the financial assumptions for the cost-effectiveness analysis. Appendix C Technical Appendix of Idaho Power s 2015 IRP contains the DSM Alternate costs, discount rate, and escalation rate. These DSM Alternate costs vary by season and time of day and are applied to an end-use load shape to obtain the value of a measure or program. The DSM Alternate energy costs are based on both the projected fuel costs of a peaking unit and forward electricity prices as determined by Idaho Power s power supply model, AURORAxmp Electric Market Model. The avoided capital cost of capacity is based on a gas-fired, simple-cycle turbine. In the 2015 IRP, the annual avoided capacity cost is $119 per kilowatt (kw). Page 4 Demand-Side Management 2017 Annual Report

9 Idaho Power Company Supplement 1: Cost-Effectiveness As part of the 2015 IRP Case IPC-E 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 The estimated average value of energy efficiency on T&D deferral is $3.76/kW per year or $ /kilowatt-hour (kwh). In compliance with Order No , this value was added to the 2015 DSM Alternate energy costs and included in the cost-effectiveness analysis for Idaho Power s 2017 IRP was filed on June 30, 2017 with the IPUC under case IPC-E and with the OPUC under case LC 68. Idaho Power s 2017 IRP was acknowledged by the IPUC on February 9, 2018, in Order No As of the publication of this report, the company has not received an acknowledgement of the 2017 IRP from Oregon. Since the 2017 IRP was acknowledged after the budgets were set for 2018, the 2015 IRP will remain the source for all financial assumptions and cost effectiveness analysis in The 2017 IRP is expected to be the source of all assumptions and analysis for the 2019 program year. For the demand response programs, with inputs from the 2017 IRP, the Company determined the maximum annual cost of running all three demand response programs for the maximum allowable hours of 60 hours has been calculated to be no more than $19.8 million. As recommended by the NAPEE Understanding Cost-Effectiveness of Energy Efficiency Programs Idaho Power s weighted average cost of capital (WACC) of 6.74 percent is used to discount future benefits and costs to today s dollars. Once the DSM Alternate costs and load shapes are applied to the annual kwh savings of a measure or program, the WACC is used to calculate the net present value (NPV) of the annual benefit for the UC and TRC B/C ratios. However, determining the appropriate discount rate for participant cost and benefits is difficult because of the variety of potential discount rates that can be used by the different participants as described in the TAG. Since the participant benefit is based on the anticipated bill savings of the customer, Idaho Power believes the WACC is not an appropriate discount rate to use. Because the customer bill savings is based on Idaho Power s 2017 average customer segment rate and is not escalated, the participant bill savings is discounted using a real discount rate of 4.44 percent, which is based on the 2015 IRP s WACC of 6.74 percent and an escalation rate of 2.2 percent. The real discount rate is used to calculate the NPV of any participant benefits or costs for the PCT or ratepayer impact measure (RIM) B/C ratios. The formula to calculate the real discount rate is as follows: ((1 + WACC) (1 + Escalation)) 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 2017 Annual Report shows the estimated electrical savings at the customer meter level. Cost-effectiveness analyses are based on generation-level energy savings. The demand response program reductions are reported at the generation level with the line losses. In 2014, Idaho Power reviewed the system loss coefficients from Based on this study, the line-loss factors were updated and reduced from 10.9 to 9.6 percent. The summer peak line-loss factor was reduced from 13 to 9.7 percent. Demand-Side Management 2017 Annual Report Page 5

10 Supplement 1: Cost-Effectiveness Idaho Power Company Conservation Adder The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act) states the following: any conservation or resource shall not be treated as greater than that of any non conservation measure or resource unless the incremental system cost of such conservation or resource is in excess of 110 per centum of the incremental system cost of the nonconservation measure or resource. As a result of the Northwest Power Act, most utilities in the Pacific Northwest add a 10-percent conservation adder in energy efficiency cost-effectiveness analyses. In OPUC Order No , 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 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 s of other utilities in the Pacific Northwest, as well as the OPUC Order No and IPUC Order 32788, Idaho Power began applying the 10-percent conservation adder in all energy efficiency measure and program cost-effectiveness analyses in However, on further examination, Idaho Power observed that both Avista and Rocky Mountain Power only apply the 10-percent conservation adder when calculating the TRC test. Previously, Idaho Power had applied the adder to the TRC test and the UC and RIM tests. Beginning in 2016, Idaho Power removed the conservation adder from the UC and RIM tests in the program and measure cost-effectiveness calculations. Net-to- Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE s Understanding Cost Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers as a ratio that does as follows: Adjusts the impacts of the programs so that they only reflect those energy efficiency gains that are the result of the energy efficiency program. Therefore, the NTG deducts energy savings that would have been achieved without the efficiency program (e.g., free-riders ) and increases savings for any spillover effect that occurs as an indirect result of the program. Since the NTG attempts to measure what the customers would have done in the Page 6 Demand-Side Management 2017 Annual Report

11 Idaho Power Company Supplement 1: Cost-Effectiveness 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 results in Supplement 1: Cost-Effectiveness. Results Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis. As part of Supplement 1: Cost-Effectiveness and where applicable, Idaho Power publishes the cost-effectiveness by measure, calculating the PCT and RIM test at the program level, listing the assumptions associated with cost-effectiveness, and citing sources and dates of metrics used in the cost-effectiveness calculation. The B/C ratio from the participant cost perspective is not calculated for the 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 2017 Annual Report Appendix 4 contains program UC and TRC B/C ratios using actual cost information over the life of the program through Supplement 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using actual information from 2017 and includes results of the PCT. Current customer energy rates are used in the calculation of the B/C ratios from a PCT and RIM perspective. Rate increases are not forecasted or escalated. A summary of the cost-effectiveness by program can be found in Table 3. The application of the 2015 DSM Alternate costs impacted the cost-effectiveness ratios for all programs and measures within the DSM portfolio. The DSM Alternate costs declined on average 24 percent between the 2013 and 2015 IRPs. However, in 2017, most of Idaho Power s energy efficiency programs were cost-effective from the UC or TRC perspective with the exception of the Fridge and Freezer Recycling Program, Heating & Cooling Efficiency (H&CE) Program, Home Improvement Program, and the weatherization programs for income-qualified customers. The Fridge and Freezer Recycling Program has a UC of 0.60 and a TRC of The program s cost-effectiveness has been an ongoing discussion with EEAG since 2014 due to declining deemed savings values from the RTF and Idaho Power s DSM Alternate costs. In an attempt to lower program administrative costs, the $30 incentive was removed in 2015 and customers were given two LED lightbulbs for additional energy savings. When the incentives were removed, participation declined from over 3,194 units in 2014 to 1,630 units in The program faced additional challenges when Demand-Side Management 2017 Annual Report Page 7

12 Supplement 1: Cost-Effectiveness Idaho Power Company the original program vendor entered into receivership and ceased operations in late Idaho Power temporarily suspended the program and re-launched it in June 2016 under a new name and with a new program vendor. At that time, the OPUC authorized the program s reinstatement in Idaho Power s Oregon service territory; however, it imposed certain specific reporting requirements. Specifically, the OPUC requested that in 2017, the company re-evaluate the program s cost effectiveness using the unit energy savings based on the vintage (e.g., 1992 and earlier and 1993 and later ) of the recycled unit as well as the any vintage. When the program began in 2009, 90 percent of the freezer recycled were 1992 an older. In 2017, 55 percent of freezers were of that vintage. In 2009, 78 percent of refrigerators recycled in the program were vintage year 1992 and older. By 2017, 26 percent of the refrigerators were that vintage. Because older units have higher savings and fewer of those units have been recycled through the program, the program was increasingly becoming less cost-effective. In early 2017, Idaho Power projected that if the program recycled 1,800 units, it would fail the UC and the TRC tests. The company continued to monitor the program and by mid-summer, the program had recycled only 790 units. It appeared the program would be on pace to only recycle 1,500 units by year end. Based on the projected lower participation levels, the program was expected to be not be cost-effective under either test. Other regional utilities such as Avista, Rocky Mountain Power, Energy Trust of Oregon had recently discontinued their programs. Seattle City Light was in the process of suspending its program. Idaho Power presented these findings at the August 2, 2017, EEAG meeting. The EEAG members in attendance supported the recommendation to end the program. The program s higher than anticipated UC and TRC for 2017 was largely due to the large push toward the end of the year to increase the program s participation before its discontinuation as well as a reduction to the program s administrative costs. Due to updated savings from the RTF, the program is still anticipated to be not cost-effective in future years. The Heating & Cooling Efficiency Program has a UC of 1.48, TRC of 0.85, PCT of In 2016, Idaho Power reviewed the program s cost-effectiveness and notified EEAG at the August 30, 2016, meeting that the program was anticipated to be not cost-effective from the TRC perspective. Throughout 2017, Idaho Power discussed with EEAG proposed tactics it would implement to improve the program s overall cost-effectiveness. These tactics include re-assigning non-program labor, reducing marketing spend while improving other tactics, and reducing the stipend to participating contractors. Idaho Power also proposed to report the cost-effectiveness of the ductless heat pumps (DHP), which are not cost-effective, separately from the rest of the program. After reviewing the costs that were allocated to the DHP portion of the program compared to the rest of the program, it appears that the DHP portion of the program was assigned only 13 percent of the total administrative costs. As a result, the DHP portion of the program had a UC of 1.87 and TRC of 0.80 while the rest of the program had a UC of 1.35 and TRC of Idaho Power filed changes to the program in October 2017 with the OPUC. Effective January 1, 2018, the program has reduced the contractor stipend from $150 to $50 and added heat pump water heaters to the measure offerings. The inclusion of the heat pump water heater measure may increase the potential Page 8 Demand-Side Management 2017 Annual Report

13 Idaho Power Company Supplement 1: Cost-Effectiveness energy savings in the program without significantly increasing administrative costs, which may improve the program s overall cost-effectiveness. The company plans to continue to monitor this program and seek opportunities to improve the program s overall cost-effectiveness. The Home Improvement Program has a UC of 2.54, a TRC of 0.41, and a PCT of Due to the reduced weatherization savings from the RTF, as well as the DSM Alternate costs from the 2015 IRP, further reduce the cost-effectiveness of the program. Idaho Power analyzed ways to modify the program to improve the cost-effectiveness, but despite the long 45-year life of the program and measures, the company concluded the program would remain not cost-effective. The company ended the program in June WAQC had a TRC of 0.48 and a UC ratio of 0.37, and Weatherization Solutions for Eligible Customers had a TRC of 0.46 and a UC ratio of The programs showed a decrease in savings and cost effectiveness ratios over The decrease to the program s overall cost-effectiveness is due in part to the lower DSM Alternate costs from the 2015 IRP as well as the updated load shapes that reflect most of the savings for the program occur in the non-summer months. In 2017, Idaho Power began using the load shape for the programs analysis that was used for electric space heating in Idaho Power s 2015 and 2017 potential studies. The load shapes reflect the time periods of the energy savings end uses. The load shape change reduced the value of the savings allocated to summer months and better aligns with the electric heat nature of the program savings. To calculate the programs cost effectiveness, Idaho Power adopted the following IPUC staff s recommendations from Case No. GNR E-12-01: Applied a 100-percent NTG. Claimed 100 percent of energy savings for each project. Included indirect administrative overhead costs. The overhead costs of 6.13 percent were calculated from the $2,929,093 of indirect program expenses divided by the total DSM expenses of $47,757,496 as shown in Appendix 3 of the Demand-Side Management 2017 Annual Report. Applied the 10 percent conservation preference adder. Amortized evaluation expenses over a three-year period. Claimed one dollar of NEBs for each dollar of utility and federal funds invested in health, safety, and repair measures. Thirty-seven out of 268 individual measures in various programs are shown to not be cost-effective from either the UC or TRC perspective. The increase in non cost-effective measures largely due to the lower DSM Alternate costs. These measures will be discontinued, analyzed for additional NEBs, modified to increase potential per-unit savings, or monitored to examine their impact on the specific program s overall cost-effectiveness. Specifically, of the 37 non cost-effective measures, 12 have been removed from the programs, 12 have ratios between , and 7 have ratios between For several Demand-Side Management 2017 Annual Report Page 9

14 Supplement 1: Cost-Effectiveness Idaho Power Company measures, Idaho Power filed cost-effectiveness exception requests with the OPUC in compliance with Order No s 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 These exception requests were approved under Order No on June 23, 2015, or with the specific program advice filings. The filings and exception requests are noted in Table 1. Table non-cost-effective measures Program Energy Efficient Lighting Number of s Notes 3 Program is cost-effective with a UC of 4.09 and TRC of The non-cost-effective measures were a CFL decorative and mini base bulb, a CFL globe, and a CFL reflector. These 107 bulbs were carry overs from 2016 and represent % of overall bulbs purchased in the program. Additionally, CFL bulbs have been removed from the Simple Steps, Smart Savings lighting promotion. 4 Program was discontinued on December 31, Fridge and Freezer Recycling Program H&CE Program 6 Cost-effectiveness exception request for ductless heat pumps (DHP) and open-loop water source heat pumps filed with the OPUC under UM OPUC Order No , Section 13. Approved under Order No Exception request for the program and smart thermostat requested and approved with OPUC Advice No Air-source heat pump and duct sealing measures would be cost-effective at 1.33 and 1.03 respectively without the inclusion of administration costs. Meets OPUC Order No , Section 10. Home Improvement 5 Program was discontinued on June 30, Program Rebate Advantage 2 ENERGY STAR and Eco-Rated manufactured homes built in Heating Zone 1 have a TRC of 0.94 and 0.95 respectively. s would be cost-effective with TRCs of 1.11 and 1.12 without the inclusion of administration costs. Meets OPUC Order No , Section 10. Program to be reviewed in 2018 with updated RTF assumptions. New Construction and Retrofits 4 s offered in both options. Cost-effectiveness exception request filed and approved with OPUC Advice No , 14-10, and OPUC Order No , Section 13. Exceptions C and D. Program to be reviewed in 2018 with program updates. New Construction 2 Cost-effectiveness exception request filed and approved with OPUC Advice No and OPUC Order No , Section 13. Exceptions A and D. Program to be reviewed in 2018 with program updates. Retrofit 10 UC and TRC ranges from 0.76 to Cost-effectiveness exception request filed and approved with OPUC Advice No and OPUC Order No , Section 13. Exceptions C and D. Program to be reviewed in 2018 with program updates. Irrigation Efficiency Rewards Program Total 37 1 has a UC of 3.71 and TRC of Cost-effectiveness exception request for rebuilt or new brass impact sprinklers filed with the OPUC under UM OPUC Order No , Section 13. Exception A, D, and D. Approved under Order No Following the annual program cost-effectiveness results are tables that include measure-level cost-effectiveness. Exceptions to the measure-level tables are programs that are analyzed at the project level. These programs include, Custom Projects, the custom option of 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. Page 10 Demand-Side Management 2017 Annual Report

15 Idaho Power Company Supplement 1: Cost-Effectiveness 2017 DSM Detailed Expenses by Program Included in this supplement is a detailed breakout of program expenses as shown in Appendix 2 of the Demand Side Management 2017 Annual Report. These expenses are broken out by funding source major-expense type (labor/administration, materials, other expenses, purchased services, and incentives). Table DSM detailed expenses by program (dollars) Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Energy Efficiency/Demand Response Total $ 28,624,709 $ 1,129,736 $ 1,574,128 $ 31,328,572 Residential Total $ 11,661,597 $ 227,882 $ 1,497,964 $ 13,387,443 Easy Savings , ,813 Labor/Administrative Expense... 24,772 24,772 Materials and Equipment , ,000 Other Expense Educational Distributions... 3,323, ,860 1,143 3,466,027 Labor/Administrative Expense... 41,055 2,132 1,143 44,330 Materials and Equipment... 2,706, ,731 2,835,998 Other Expense ,442 9, ,439 Purchased Services , ,260 Energy Efficient Lighting... 4,787,259 84,223 1,406 4,872,888 Labor/Administrative Expense... 61,567 3,317 1,406 66,291 Materials and Equipment Other Expense... 1, ,130 Purchased Services... 2,082,484 30,358 2,112,841 Incentives... 2,642,134 50,491 2,692,626 Energy House Calls ,691 12, ,035 Labor/Administrative Expense... 15, ,305 Materials and Equipment... 2, ,496 Other Expense... 15, ,442 Purchased Services ,457 10, ,793 Fridge and Freezer Recycling Program ,480 6, ,942 Labor/Administrative Expense... 18, ,641 Materials and Equipment... 6, ,328 Other Expense... 27,207 1,103 28,310 Purchased Services ,905 3, ,662 Heating & Cooling Efficiency Program ,404 18,920 2, ,198 Labor/Administrative Expense ,185 6,057 2, ,115 Materials and Equipment... 6, ,709 Other Expense... 70, ,760 Purchased Services ,381 5, ,988 Incentives ,325 6, ,625 Home Energy Audit ,125 1, ,809 Labor/Administrative Expense... 59,478 1,683 61,161 Materials and Equipment... 20,639 20,639 Other Expense... 71,515 71,515 Purchased Services , ,494 Home Improvement Program ,483 1, ,830 Labor/Administrative Expense... 51,670 1,347 53,017 Other Expense Purchased Services... 2,393 2,393 Incentives , ,183 Multifamily Energy Savings Program , ,216 Labor/Administrative Expense... 34, ,430 Materials and Equipment... 72,324 72,324 Other Expense Demand-Side Management 2017 Annual Report Page 11

16 Supplement 1: Cost-Effectiveness Idaho Power Company Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Purchased Services... 59,555 59,555 Oregon Residential Weatherization... 2, ,384 Labor/Administrative Expense... 1, ,955 Other Expense Incentives Rebate Advantage... 93,891 10, ,996 Labor/Administrative Expense... 10, ,867 Other Expense... 14, ,137 Purchased Services... 11,382 1,610 12,992 Incentives... 58,000 8,000 66,000 Residential New Construction Pilot Program ,637 2, ,520 Labor/Administrative Expense... 27,695 1, ,839 Materials and Equipment Other Expense... 15, ,323 Purchased Services Incentives , ,000 Shade Tree Project ,695 1, ,817 Labor/Administrative Expense... 40,301 1,122 41,423 Materials and Equipment Other Expense... 24,858 24,858 Purchased Services... 53,975 53,975 Incentives... 75,557 75,557 Simple Steps, Smart Savings ,354 5, ,621 Labor/Administrative Expense... 42,414 2, ,127 Other Expense Purchased Services... 44,446 1,315 45,762 Incentives... 98,423 2, ,659 Weatherization Assistance for Qualified Customers 1,307,485 1,307,485 Labor/Administrative Expense... 40,242 40,242 Materials and Equipment... 4,246 4,246 Other Expense... 7,390 7,390 Purchased Services... 1,255,607 1,255,607 Weatherization Solutions for Eligible Customers 1,137,209 (56,571) 28,224 1,108,862 Labor/Administrative Expense... 7,963 28,224 36,186 Materials and Equipment... 4,246 4,246 Other Expense... 14,996 14,996 Purchased Services... 1,110,004 (56,571) 1,053,433 Commercial/Industrial $ 14,732,314 $ 709,437 $ 23,701 $ 15,465,452 Custom Projects... 8,352, ,028 16,266 8,679,919 Labor/Administrative Expense ,367 29,009 16, ,577 Materials and Equipment... 3, ,763 Other Expense ,873 15, ,350 Purchased Services... 1,300,586 60,548 1,361,134 Incentives... 6,200, ,870 6,406,095 New Construction... 2,186, ,129 4,254 2,433,596 Labor/Administrative Expense ,195 10,660 4, ,110 Other Expense... 37,257 1,961 39,218 Purchased Services ,893 7, ,820 Incentives... 1,793, ,581 2,016,449 Retrofits... 4,193, ,180 3,180 4,343,835 Labor/Administrative Expense ,373 15,025 3, ,578 Materials and Equipment Page 12 Demand-Side Management 2017 Annual Report

17 Idaho Power Company Supplement 1: Cost-Effectiveness Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Other Expense... 50,204 2,642 52,847 Purchased Services ,754 38, ,300 Incentives... 3,124,883 90,952 3,215,835 Oregon Commercial Audits... 8,102 8,102 Labor/Administrative Expense... 3,848 3,848 Materials and Equipment Other Expense Purchased Services... 3,300 3,300 Irrigation Total $ 2,230,798 $ 192,416 $ 52,463 $ 2,475,677 Irrigation Efficiency Rewards... 2,230, ,416 52,463 2,475,677 Labor/Administrative Expense ,863 16,759 52, ,072 Materials and Equipment... 1, ,837 Other Expense... 72,622 3, ,457 Purchased Services... 4, ,716 Incentives... 1,842, ,033 2,013,594 Market Transformation Total $ 2,563,818 $ 134,938 $ $ 2,698,756 NEAA... 2,563, ,938 2,698,756 Purchased Services... 2,563, ,938 2,698,756 Other Program and Activities Total $ 1,837,807 $ 97,468 $ 47,958 $ 1,983,232 Commercial/Industrial Energy Efficiency Overhead 336,335 18,472 33, ,135 Labor/Administrative Expense ,875 10,986 33, ,189 Materials and Equipment Other Expense ,538 6, ,567 Purchased Services... 26,598 1,441 28,039 Energy Efficiency Direct Program Overhead ,251 17,628 5, ,574 Labor/Administrative Expense ,674 11,127 5, ,495 Other Expense... 84,577 6,501 91,078 Residential Energy Efficiency Education Initiative.. 210,215 11,152 2, ,880 Labor/Administrative Expense... 84,214 4,560 2,492 91,265 Materials and Equipment... 1, ,392 Other Expense ,544 6, ,451 Purchased Services... (6,866) (361) (7,228) Residential Energy Efficiency Overhead... 1,001,005 50,217 6,421 1,057,643 Labor/Administrative Expense ,629 9,001 6, ,972 Materials and Equipment Other Expense ,200 37, ,293 Purchased Services ,967 4, ,158 Indirect Program Expenses Total $ 2,733,799 $ 46,651 $ 148,957 $ 2,929,407 All Sectors Total $ 2,733,799 $ 46,651 $ 148,957 $ 2,929,407 Energy Efficiency Accounting and Analysis ,239 45, ,830 1,072,797 Labor/Administrative Expense ,954 27, , ,950 Materials and Equipment Other Expense... 18,935 1,006 23,497 43,437 Purchased Services ,299 17, ,356 Energy Efficiency Advisory Group... 21,685 1, ,959 Labor/Administrative Expense... 4, ,909 Other Expense... 17, ,050 Special Accounting Entries... 1,833,875 (225) 1,833,651 Special Accounting Entry... 1,833,875 (225) 1,833,651 Demand-Side Management 2017 Annual Report Page 13

18 Supplement 1: Cost-Effectiveness Idaho Power Company Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Demand Response Total $ 1,325,951 $ 476,305 $ 7,015,273 $ 8,817,529 Residential Total $ 495,142 $ 39,493 $ 401,638 $ 936,272 A/C Cool Credit ,142 39, , ,272 Labor/Administrative Expense... 54,783 2,960 1,525 59,268 Materials and Equipment... 5, ,506 Other Expense... 23,192 1,221 24,412 Purchased Services ,940 29, ,731 Incentives... (4) 5, , ,353 Commercial/Industrial Total $ 86,861 $ 231,285 $ 340,010 $ 658,156 Flex Peak Program... 86, , , ,156 Labor/Administrative Expense... 72,582 3,924 2,021 78,527 Other Expense... 3, ,657 Purchased Services... 11,019 11,019 Incentives , , ,954 Irrigation Total $ 743,948 $ 205,528 $ 6,273,625 $ 7,223,101 Irrigation Peak Rewards , ,528 6,273,625 7,223,101 Labor/Administrative Expense... 63,714 3,448 28,103 95,264 Materials and Equipment ,184 10, ,615 Other Expense... 2, ,267 Purchased Services ,986 24, ,656 Incentives ,869 6,245,430 6,412,299 Grand Total $ 37,086,084 $ 1,885,098 $ 8,786,314 $ 47,757,496 Page 14 Demand-Side Management 2017 Annual Report

19 Idaho Power Company Supplement 1: Cost-Effectiveness Table 3. Cost-effectiveness of 2017 programs by B/C test Program/Sector UC TRC RIM PCT Educational Distributions N/A Energy Efficient Lighting Energy House Calls N/A Fridge and Freezer Recycling Program N/A Heating & Cooling Efficiency Program Home Improvement Program Multifamily Energy Savings Program N/A Rebate Advantage Residential New Construction Pilot Program (ENERGY STAR Homes Northwest) Simple Steps, Smart Savings Weatherization Assistance for Qualified Customers N/A Weatherization Solutions for Eligible Customers N/A Residential Energy Efficiency Sector Custom Projects New Construction Retrofits Commercial/Industrial Energy Efficiency Sector* Irrigation Efficiency Rewards Irrigation Energy Efficiency Sector** Energy Efficiency Portfolio *Commercial/Industrial Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Rewinds. **Irrigation Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Rewinds. Demand-Side Management 2017 Annual Report Page 15

20 Supplement 1: Cost-Effectiveness Idaho Power Company Educational Distributions Segment: Residential 2017 Program Results Cost-Effectiveness Tables by Program Cost Inputs Ref Program Administration... $ 3,466,027 Program Incentives... I Total UC... $ 3,466,027 P Equipment and Installation (Incremental Participant Cost)... $ M Summary of Cost-Effectiveness Results Test Benefit Cost Ratio UC Test... $ 10,481,423 $ 3,466, TRC Test... 21,929,694 3,466, RIM Test... 10,481,423 19,663, PCT... N/A N/A N/A Net Benefit Inputs (NPV) Ref Resource Savings 2017 Annual Energy (kwh)... 21,187,261 NPV Cumulative Energy (kwh) ,777,127 $ 10,481,423 S 10% Credit (Northwest Power Act)... 1,048,142 Total Electric Savings... $ 11,529,566 A Participant Bill Savings NPV Cumulative Participant Bill Savings... $ 16,197,275 B Other Benefits Non-Utility Rebates/Incentives... $ NUI NEBs... $ 10,400,128 NEB Benefits and Costs Included in Each Test UC Test... = S * NTG = P TRC Test... = (A + NUI + NEB) * NTG = P RIM Test... = S * NTG = P + (B * NTG) PCT... N/A N/A Assumptions for Levelized Calculations Discount Rate Nominal (WACC) % Real ((1 + WACC) / (1 + Escalation)) % Escalation Rate % Net-to- (NTG) % Minimum NTG Sensitivity... 33% Average Customer Segment Rate/kWh... $0.087 Line Losses % Notes: Energy savings as reported by the Resource Action Plan for the 2016 to 2017 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 costs. Page 16 Demand-Side Management 2017 Annual Report

21 Idaho Power Company Supplement 1: Cost-Effectiveness Year: 2017 Program: Educational Distributions Market Segment: Residential Program Type: Energy Efficiency Name Descriptions Replacing General Purpose LED Give away Student Energy Efficiency Kit (SEEK) Program Energy- Savings Kit Efficient Technology: LED Lamp Type: General purpose and dimmable Lumen Category: 250 to 1049 lumens Space Type: Any kit offering. Kits include: highefficiency showerhead, shower timer, 3 LEDs, FilterTone alarm, digital thermometer, LED nightlight. Nine lumen general purpose bulbs One 1.75-gallons per minute (gpm) highefficiency showerheads or showerhead and thermostatic shower valve combo (electric kit only) Three faucet aerators (electric kit only) Energy Savings (kwh/yr) b Benefit Cost B/C Tests NPV DSM Avoided Costs c Incremental Participant Cost d Admin Cost TRC ($/kwh) e UC Ratio f Ratio g Incentive/ Unit End Use Life (yrs) a NEB Unit Source Baseline bulb Lamp ENRes_SF_Lighting $5.06 $8.95 $ No kit Kit IPC_Student Kits $ $ $ No kit Kit IPC_Energy-savings Kits $ $ $ 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 2015 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act. d No participant costs. e Average program administration and overhead costs to achieve each kwh of savings. Calculated from 2017 actuals. f UC Ratio = (NPV DSM Avoided Costs) / ((Admin Cost/kWh * kwh Savings) + Incentives) g TRC Ratio = ((NPV DSM Avoided Costs * 110%) + NEB / ((Admin Cost/kWh * kwh Savings) + Incentives + (Incremental Participant Cost - Incentives)) 1 RTF. ResLighting_Bulbs_v4_2.xlsm Resource Action Programs Idaho Power Energy Wise Program Summary Report Lightbulbs RTF. ResLighting_Bulbs_v4_2.xlsm. Showerhead - RTF. ResShowerheads_v2_4.xlsm Faucet aerators AEG. Potential Study. Demand-Side Management 2017 Annual Report Page 17

22 Supplement 1: Cost-Effectiveness Idaho Power Company Energy Efficient Lighting Segment: Residential 2017 Program Results Cost Inputs Ref Program Administration... $ 2,180,262 Program Incentives... 2,692,626 I Total UC... $ 4,872,888 P Equipment and Installation (Incremental Participant Cost) $ 8,898,728 M Summary of Cost-Effectiveness Results Test Benefit Cost Ratio UC Test... $ 19,946,368 $ 4,872, TRC Test... 51,259,943 11,078, RIM Test... 19,946,368 35,746, PCT... 62,885,516 8,898, Net Benefit Inputs (NPV) Ref Resource Savings 2017 Annual Energy (kwh)... 37,765,190 NPV Cumulative Energy (kwh) ,265,652 $ 19,946,368 S 10% Credit (Northwest Power Act)... 1,994,637 Total Electric Savings... $ 21,941,005 A Participant Bill Savings NPV Cumulative Participant Bill Savings... $ 30,873,952 B Other Benefits Non-Utility Rebates/Incentives... $ NUI NEBs... $ 29,318,938 NEB Benefits and Costs Included in Each Test UC Test... = S * NTG = P TRC Test... = (A + NUI + NEB) * NTG = P + ((M-I) * NTG) RIM Test... = S * NTG = P + (B * NTG) PCT... = B + I + NUI + NEB = M Assumptions for Levelized Calculations Discount Rate Nominal (WACC) % Real ((1 + WACC) / (1 + Escalation)) % Escalation Rate % Net-to- (NTG) % Minimum NTG Sensitivity... 25% Average Customer Segment Rate/kWh... $0.087 Line Losses % Note: NEBs include PV of periodic bulb (capital) replacement costs. Page 18 Demand-Side Management 2017 Annual Report