20150316DSM 2014 Supplement 1.pdf

March 15, 2015
2014 ANNUAL REPORT
Demand-Side Management
SUPPLEMENT 1:
Cost-Effectiveness
SUPPLEMENT 1:
Cost-Effectiveness
Printed on recycled paper
Idaho Power Company Supplement 1: Cost-Effectiveness
TABLE OF CONTENTS
Table of Contents ......................................................................................................................................... i
List of Tables ............................................................................................................................................... i
Supplement 1: Cost-Effectiveness ...............................................................................................................1
Cost-Effectiveness .................................................................................................................................1
Methodology ....................................................................................................................................2
Assumptions .....................................................................................................................................3
Conservation Adder .........................................................................................................................5
Net-to-Gross .....................................................................................................................................5
Results ..............................................................................................................................................6
2014 DSM Detailed Expense by Program .............................................................................................9
Cost-Effectiveness Tables by Program ......................................................................................................15
Ductless Heat Pump Pilot ..............................................................................................................15
Energy Efficient Lighting ..............................................................................................................17
Energy House Calls........................................................................................................................23
ENERY STAR® Homes Northwest ...............................................................................................27
Heating & Cooling Efficiency Program ........................................................................................29
Home Improvement Program ........................................................................................................33
Home Products Program ................................................................................................................35
Rebate Advantage ..........................................................................................................................39
See ya later, refrigerator® ...............................................................................................................41
Student Energy Efficiency Kit .......................................................................................................43
Weatherization Assistance for Qualified Customers .....................................................................45
Weatherization Solutions for Eligible Customers..........................................................................47
Building Efficiency ........................................................................................................................49
Custom Efficiency .........................................................................................................................53
Easy Upgrades ...............................................................................................................................57
Irrigation Efficiency Rewards ........................................................................................................65

LIST OF TABLES
Table 1. 2014 non-cost-effective measures ........................................................................................8
Table 2. 2014 DSM detailed expenses by program (dollars) .............................................................9
Table 3. Cost-effectiveness summary by program...........................................................................13
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SUPPLEMENT 1: COST-EFFECTIVENESS
Cost-Effectiveness
Idaho Power considers cost-effectiveness of primary importance in the design, implementation,
and tracking of energy efficiency and demand response programs. Idaho Power’s energy efficiency and
demand response opportunities are preliminarily identified through the Integrated Resource Plan (IRP)
process. Idaho Power uses third-party energy efficiency potential studies to identify achievable cost-effective energy efficiency potential that is added to the resources included in the IRP. In early 2014, Idaho Power convened a Program Planning Group to explore new opportunities to expand current
demand-side management (DSM) programs and offerings. Because of Idaho Power’s diversified
portfolio of programs, most of the new potential for energy efficiency in Idaho Power’s service area is
based on additional measures to be added to existing programs rather than developing new programs.
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 ESource, the Edison Electrical Institute (EEI), 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. In 2014, Idaho Power contracted with ADM Associates, Inc.; CLEAResult
Consulting, Inc.; Evergreen Economics; Johnson Consulting Group; and Tetra Tech, MA for program
evaluations and research.
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. If a particular measure or program is pursued even though it will not
be 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 delineated in the memorandum of understanding (MOU) under Idaho Public Utilities Commission (IPUC) Case No. IPC-E-09-09 and Public Utility Commission of Oregon (OPUC) Order
No. 94-590.
In the OPUC Order No. 94-590, issued in 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 which 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
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
Demand-Side Management 2014 Annual Report Page 1
Supplement 1: Cost-Effectiveness Idaho Power Company
D. Inclusion of the measure helps to 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 measures 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.
Idaho Power endeavors to offer identical programs in both its Oregon and Idaho jurisdictions since 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, could inhibit participation, and would add to administration costs.
In addition, program infrastructure is designed to implement consistent programs across the service area.
Methodology
For its cost-effectiveness methodology, Idaho Power relies on the Electric Power Research Institute (EPRI) End Use Technical Assessment Guide (TAG); the California Standard Practice Manual and its
subsequent addendum, the National Action Plan for Energy Efficiency’s (NAPEE) Understanding
Cost-Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging
Issues for Policy-Makers; and the National Action Plan on Demand Response. Traditionally, 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.
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 2014 dollars. The result of the one-year perspective is shown in
Supplement 1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2014 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.
Demand response programs are expensive and generally have a higher initial investment than energy efficiency programs.
The methods used to determine the cost-effectiveness of the demand response programs was updated in
2014. As part of the public workshops in conjunction with 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 annual cost of operating the three demand-response programs for the maximum allowable 60 hours be no more than $16.7 million. This $16.7 million value is the levelized annual cost of a 170 MW deferred resource over
a 20-year life. The demand response value calculation will include this value even in years when the IRP
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Idaho Power Company Supplement 1: Cost-Effectiveness
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 2014,
the cost of operating the three demand response programs was $10.6 million. Idaho Power estimates that
if the three programs were dispatched for the full 60 hours, the total costs would have been approximately $13.8 million and would have remained cost effective.
In reviewing the measure cost-effectiveness analyses, Idaho Power examined how the company defines
a measure and the level of granularity to be shown in this report. As a result of this examination,
the number of measures reported in Supplement 1: Cost-Effectiveness has been reduced from 455 in
2013 to 259 in 2014. Idaho Power offers attic insulation to Idaho residential customers in the Home Improvement Program. To a customer, attic insulation would be considered one measure or offering.
In 2013, Idaho Power displayed 81 different attic insulation measure combinations representing various
R-values, heating systems, and heating and cooling zones within its service area.
Idaho Power has consolidated the measure definition for the attic-, floor-, and wall-insulation and
window measures in the Home Improvement Program. The company has also consolidated the lighting measures in the Easy Upgrades program. In 2014, Idaho Power made several changes to the standard
lighting measure offering within Easy Upgrades. These changes resulted in over 100 lighting measure
combination in the program. These lighting measures have been grouped under 26 similar categories.
Assumptions
Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumptions
for various measures. These assumptions are routinely reviewed and updated as new information becomes available. For many of the measures within Supplement 1: Cost-Effectiveness, savings, costs, and load shapes were derived from either the Regional Technical Forum (RTF) or the Idaho Power
Energy Efficiency Potential Study conducted by EnerNOC Utility Solutions Consulting Group
(EnerNOC) in 2012. In 2013, EnerNOC provided Idaho Power with 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.
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 the monthly meetings and contributing to various sub-committees. Because cost data from the RTF information is in 2006 dollars, measures with costs from the RTF have been escalated by 17.50232 percent in 2014. This percentage is provided
by the RTF at rtf.nwcouncil.org/measures/support/files/RTFStandardInformationWorkbook_v2_2.xlsx.
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. In 2013, ADM Associates, Inc., began developing a
technical reference manual (TRM) for the Building Efficiency and Easy Upgrades programs.
Idaho Power received the results of the TRM in 2014 and has applied those assumptions to the
programs. Occasionally, Idaho Power will also use internal engineering estimates and calculations for savings and costs based on information gathered from previous projects.
In 2014, Idaho Power reviewed its policy to update measure energy savings throughout the year. In the
past, when energy savings assumptions were updated during the calendar year by third-parties, such as
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Supplement 1: Cost-Effectiveness Idaho Power Company
the RTF or an evaluator, Idaho Power immediately applied those assumptions retroactively for the entire
year. This caused issues when budgets and goals are set at the beginning of the year using one set of
assumptions and those assumptions are changed mid-year. This made it appear that some programs were
not meeting their original goals. It has been recommended in process evaluations that the company “freeze” savings assumptions at a certain point and update assumptions once a year. After reviewing the
practices of other utilities around the region and the impact of these frequent updates to program
specialists and field staff, the company established a policy to freeze savings assumptions when the
budgets and goals are set for the next calendar year unless code and standards changes or program
updates necessitate a need to use updated savings. As a general rule, the 2014 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.
The Technical Appendix of Idaho Power’s 2013 IRP is the source for the financial assumptions,
including the discount rate and escalation rate. The 2013 IRP was acknowledged by the IPUC in Order No. 32980 on February 24, 2014 and by the OPUC in Order No. 14-253 on July 8, 2014.
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 2013 IRP planning process resulted in a significant drop in the DSM alternative costs used to value energy efficiency
compared with previous IRPs. While impacts will vary from program to program depending on measure
life and the end uses, decreases of program benefits of up to 40 to 50 percent have been seen. Multiple
factors led to the reduction of the DSM alternative costs, but two of the primary impacts included a
reduced carbon adder used in the 2013 IRP process and decreases in early-year natural gas price forecasts. While these benefit reductions have placed more burden on program cost-effectiveness, some of the impact has been mitigated by the recent addition of quantified non-energy benefits (NEB) in the
region. The avoided capital cost of capacity is based on a gas-fired, simple-cycle turbine. In the 2013
IRP, the annual avoided capacity cost increased from $94 per kilowatt (kW) from the 2011 IRP to $102
per kW. When multiplied by the effective load carrying capacity (ELCC) of 93.4 percent, the annual avoided capacity cost is $95.27/kW. The ELCC reduces the avoided capacity cost benefit based on the availability of a resource.
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. 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 manual. 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 2014 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 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 2014 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
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Idaho Power Company Supplement 1: Cost-Effectiveness
losses. In 2014, Idaho Power reviewed the system loss coefficients from 2012. Based on this study,
the line loss factors were updated and reduced from 10.9 to 9.6 percent. The summer peak line loss
factor was reduced from 13 to 9.7 percent.
Conservation Adder
The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act) states:
…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.1
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 commission 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 that the utilities have the option to use a 10 percent adder and the
IPUC Commission 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 now includes the 10 percent conservation adder in all
measure and program cost-effectiveness analyses.
Net-to-Gross
Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE’s Understanding
Cost-Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers as a ratio that does as follows: Adjusts the impacts of the programs so that they only reflect those energy efficiency gains that
are the result of the energy efficiency program. Therefore, the NTG deducts energy savings that
would have been achieved without the efficiency program (e.g., ‘free-riders’) and increases
savings for any ‘spillover’ effect that occurs as an indirect result of the program. Since the NTG
attempts to measure what the customers would have done in the absence of the energy efficiency program, it can be difficult to determine precisely.

Capturing the effects of Idaho Power’s energy efficiency efforts on free-ridership and spillover is
difficult. Due to the uncertainty surrounding NTG percentages, Idaho Power used a NTG of 100 percent
1 Northwest Power Act §3(4)(D). nwcouncil.org/media/5227150/poweract.pdf

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Supplement 1: Cost-Effectiveness Idaho Power Company
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.
These NTG percentages are shown in the program cost-effectiveness pages of Supplement 1: Cost-Effectiveness.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis.
As part of Supplement 1: Cost-Effectiveness and where applicable, Idaho Power publishes the
cost-effectiveness by measure, calculating the PCT and ratepayer impact measure (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 Weatherization Assistance for
Qualified Customers (WAQC), Weatherization Solutions for Eligible Customers, See ya later,
refrigerator®, Student Energy Efficiency Kit and Energy House Calls. 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 2014 Annual Report Appendix 4 contains program
UC and TRC B/C ratios using actual cost information over the life of the program through 2014.
Supplement 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using
actual information from 2014, includes results of the PCT, and includes the application of a NTG factor where appropriate. Current customer energy rates are used in the calculation of the B/C ratios from a PCT and RIM perspective. Rate increases are not forecast or escalated. Where applicable, the
cost-effectiveness results of demand response programs include historical expenses. A summary of the
cost effectiveness by program can be found in Table 3.
In 2014, most of Idaho Power’s energy efficiency programs were cost effective, except for the Ductless Heat Pump Pilot (DHP), ENERGY STAR® Homes Northwest, See ya later, refrigerator®, Student Energy Efficiency Kit, WAQC, and Weatherization Solutions for Eligible Customers.
The DHP Pilot has a UC of 1.77, TRC of 0.70, and PCT of 1.01. In fall 2013, the RTF approved ductless
heat pump annual savings estimates for customers not screened for supplemental fuel use. RTF savings
declined from the previously provisionally deemed savings of 3,500 annual kilowatt-hour (kWh) to a range between 292 kWh and 3,131 annual kWh. As a result of the lower kWh savings, the program did not pass the TRC and PCT. In 2014, Idaho Power included RTF-approved NEBs, accounting for annual
avoided supplemental fuel costs and avoided capital expenses of A/C purchases that would have
occurred in the absence of the installation of a DHP system. A RTF sub-committee, that was formed in
2014 to address the possible inclusion of NEBs for decreased health impacts from reduced wood-burning emissions. In November, the RTF presented its findings and recommendation on the inclusion of health benefits to be part of the cost-effective benefits in the cost-effective analysis of measures and
programs. The RTF is waiting the council’s guidance on the issue. Additionally, Idaho Power filed a
cost-effectiveness exception request for the ductless heat pumps in UM-1710.
The ENERGY STAR Homes Northwest program has a UC of 1.64, TRC of 0.83, and PCT of 1.41. In 2014, 8 of 243 homes were single-family homes and 235 were townhomes. Although single-family homes are cost-effective, due to the lower kWh savings for townhomes versus single-family homes,
the program was shown to be not cost-effective from a TRC perspective for 2014. The RTF reviewed
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Idaho Power Company Supplement 1: Cost-Effectiveness
the savings assumptions for ENERGY STAR new construction for single family homes in 2014.
The RTF opted to extend the sunset date for multi-family homes and will review the measure in 2015.
Additionally, NEEA is planning to transition their Northwest ENERGY STAR Homes program to the
national EPA ENERGY STAR Homes program. A second program, NEEA’s Next Step Home program is still in the pilot stage; however, the pilot is not ready to launch as a standard program. Idaho Power
will monitor these potential changes to the program for possible implementation in the future. The
cost-effectiveness calculations for this program does not include the savings for the ENERGY STAR
certified gas heated homes that Idaho Power has claimed in 2014. Because of Idaho Power’s support of
NEEA and the Northwest ENERGY STAR Homes brand, Idaho Power is claiming savings for 282 natural gas heated, ENERGY STAR certified homes, certified in Idaho Power’s Idaho service area
in 2014. These savings account for 195,372 kWh of annual savings from efficient cooling equipment,
insulation, windows, doors, water heating, ventilation, appliances, and lighting. NEEA does not claim
these electric savings.
See ya later, refrigerator® has a UC and TRC of 0.86. The lower cost-effectiveness ratios in 2014 over 2013 are largely due to the updated 2013 IRP DSM alternative costs. In 2014, the RTF updated the
energy savings assumptions for freezer and refrigerator decommissioning and included estimates for
NEBs. The updated energy savings and NEB assumptions will be applied in 2015. With the planned
program changes in 2015 and the inclusion of NEBs, the program is expected to be cost effective
in 2015.
WAQC had a TRC of 0.42, and Weatherization Solutions for Eligible Customers had a TRC of 0.50. The cost-effectiveness ratios were impacted by the change in DSM alternative costs and the updated per
home savings. Idaho Power performed a billing analysis of the 2012 weatherization projects. In 2012
and 2013, Idaho Power claimed annual 2,684 kWh per home in WAQC. In 2014, the savings for single
family and multi-family homes decreased to 1,551 kWh per year. The savings for manufactured homes decreased to 2,568 kWh per year. The annual savings for non-profits is 1.03 kWh/heated square foot. For Weatherization Solutions for Eligible Customers, the billing analysis shows that the per home
annual savings increased. In 2012 and 2013, Idaho Power claimed 1,826 kWh per home. In 2014,
the savings for single family and multi-family homes increased to 2,108 kWh/year. The savings for
manufactured homes increased to 3,426 kWh/per year. 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 2.90 percent were calculated from the $1,065,072 of indirect program expenses divided by the total DSM
expenses of $36,713,333 as shown in Appendix 3 of the Demand-Side Management 2014
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 nine individual measures in various programs are shown to be not 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
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Supplement 1: Cost-Effectiveness Idaho Power Company
overall cost-effectiveness. For several measures, Idaho Power filed cost-effectiveness exception request
with the OPUC in compliance with Order No. 94-590. Measures and programs which do not pass these
tests may be offered by utility if they meet one or more of the following additional conditions specified
by Section 13 of Order No. 94-590. The filings and exception request is noted below.
Table 1. 2014 non-cost-effective measures
Program Number of Measures
Building Efficiency 3 Cost-effectiveness exception request filed with OPUC Advice No. 14-10. OPUC Order No. 94-590, Section 13. Exceptions A, B, C, and D.
Ductless Heat Pump Pilot 5 Cost-effectiveness exception request filed with OPUC under UM-1710. OPUC Order No. 94-590, Section 13. Exceptions A and C.
Easy Upgrades 11 Cost-effectiveness exception request filed with OPUC Advice No. 14-06. OPUC Order No. 94-590, Section 13. Exceptions A, C, and D.
ENERGY STAR Homes Northwest 1 Reviewing program design and measure offering for 2016
Heating & Cooling Efficiency Program 6 Cost-effectiveness exception request filed with OPUC under
UM-1710. OPUC Order No. 94-590, Section 13. Exceptions C and D. Measure to be reviewed in 2015. Pending updates from the RTF.
Home Improvement Program 1 Measure to be reviewed in 2015. Pending updates from the RTF.
Home Products Program 9 Program modified in 2015 to remove non
cost-effective measures.
Irrigation Efficiency Rewards 1 Cost-effectiveness exception request filed with OPUC under UM-1710. OPUC Order No. 94-590, Section 13. Exceptions A,
C, and D.
See ya later, refrigerator 2 Program modified in 2015 to reduce costs and increase overall cost-effectiveness of the program.
Total 39

Following the annual program cost-effectiveness results are tables that include measure-level
cost-effectiveness. Exceptions to the measure-level tables are the demand response programs which do
not provide incentives for installed end-use measures. Other programs not analyzed at the measure level
include Custom Efficiency, the custom option of Irrigation Efficiency Rewards, and WAQC, where projects include multiple interactive measures that are analyzed at the project level. Due to the application of a per-home annual energy savings number for Weatherization Solutions for Eligible
Customers determined by a billing analysis of the 2012 program participants, measure-level realized
energy-saving data are unavailable for 2014. The measure level cost-effectiveness analysis is not
included in this report due to the lack of realized data at the measure level.
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 which may result in minor
rounding differences.
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Idaho Power Company Supplement 1: Cost-Effectiveness
2014 DSM Detailed Expense by Program
Included in this supplement is a detailed breakout of program expenses as shown in Appendix 2 of the Demand-Side Management 2014 Annual Report. These expenses are broken out by funding source
major-expense type (incentives, labor/administration, materials, other expenses, and purchased services).
Table 2. 2014 DSM detailed expenses by program (dollars)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program

Residential
A/C Cool Credit ................................................................ $ $962,286 $$56,988 $$446,372 $$1,465,646
Labor/Administrative Expense ................................59,202 3,554 8,433 71,189
Materials and Equipment ................................216 11 0 228
Other Expense................................................................36,483 1,920 0 38,403
Purchased Services ................................865,257 45,524 0 910,781
Incentives ................................................................1,128 5,979 437,939 445,046
Ductless Heat Pump Pilot ................................ 235,099 9,614 6,733 251,446
Labor/Administrative Expense ................................50,965 3,038 6,733 60,736
Materials and Equipment ................................4 0 0 4
Other Expense................................................................41,413 2,183 0 43,596
Purchased Services ................................12,217 643 0 12,860
Incentives ................................................................130,500 3,750 0 134,250
Energy Efficient Lighting ................................ 1,860,046 45,959 3,818 1,909,823
Labor/Administrative Expense ................................39,051 2,256 3,818 45,126
Materials and Equipment ................................(180) (9) 0 (190)
Other Expense................................................................186,098 7,026 0 193,124
Purchased Services ................................295,300 8,615 0 303,915
Incentives ................................................................1,339,777 28,071 0 1,367,848
................................................................ 186,732 8,174 3,080 197,987
Labor/Administrative Expense ................................25,708 1,516 3,080 30,304
Materials and Equipment ................................13,684 3 0 13,687
Other Expense................................................................9,261 473 0 9,734
Purchased Services ................................138,079 6,183 0 144,262
ENERGY STAR® Homes Northwest ................................ 330,523 7,612 5,141 343,277
Labor/Administrative Expense ................................33,646 2,000 4,391 40,038
Other Expense................................................................63,808 3,358 750 67,917
Purchased Services ................................69 4 0 72
Incentives ................................................................233,000 2,250 0 235,250
................................ 340,551 14,627 6,836 362,014
Labor/Administrative Expense ................................56,204 3,318 6,836 66,359
Materials and Equipment ................................5,335 320 0 5,655
Other Expense................................................................50,745 2,835 0 53,579
Purchased Services ................................104,367 4,704 0 109,071
Incentives ................................................................123,900 3,450 0 127,350
Home Energy Audit ................................................................ 164,579 (248) 6,318 170,648
Labor/Administrative Expense ................................44,353 (248) 6,318 50,422
Materials and Equipment ................................22,427 0 0 22,427
Other Expense................................................................41,395 0 0 41,395
Purchased Services ................................56,404 0 0 56,404

Demand-Side Management 2014 Annual Report Page 9
Supplement 1: Cost-Effectiveness Idaho Power Company
Table 2. 2014 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Home Improvement Program ................................ $315,616 $0 $9,101 $324,717
Labor/Administrative Expense ................................71,686 0 9,101 80,788
Materials and Equipment ................................28 0 0 28
Other Expense................................................................65,168 0 0 65,168
Purchased Services ................................7,335 0 0 7,335
Incentives ................................................................171,398 0 0 171,398
Home Products Program................................ 212,787 9,250 5,139 227,176
Labor/Administrative Expense ................................53,811 3,102 5,139 62,052
Materials and Equipment ................................61 3 0 64
Other Expense................................................................7,389 483 0 7,872
Purchased Services ................................9,741 484 0 10,225
Incentives ................................................................141,786 5,177 0 146,963
Oregon Residential Weatherization ................................ 0 5,234 228 5,462
Labor/Administrative Expense ................................0 3,466 228 3,694
Other Expense................................................................0 154 0 154
Incentives ................................................................0 1,614 0 1,614
Rebate Advantage ................................................................ 57,155 5,323 753 63,231
Labor/Administrative Expense ................................7,064 413 753 8,230
Other Expense................................................................2,091 110 0 2,201
Purchased Services ................................8,000 800 0 8,800
Incentives ................................................................40,000 4,000 0 44,000
See ya later, refrigerator ................................ 562,002 12,410 1,639 576,051
Labor/Administrative Expense ................................33,696 1,844 1,639 37,179
Other Expense................................................................61,177 2,218 0 63,395
Purchased Services ................................372,989 6,668 0 379,657
Incentives ................................................................94,140 1,680 0 95,820
Shade Tree Program................................ 143,750 66 3,474 147,290
Labor/Administrative Expense ................................24,387 66 3,474 27,927
Materials and Equipment ................................2,533 0 0 2,533
Other Expense................................................................36,566 0 0 36,566
Purchased Services ................................80,265 0 0 80,265
Weatherization Assistance for Qualified Customers 0 0 1,320,112 1,320,112
Labor/Administrative Expense ................................0 0 48,908 48,908
Other Expense................................................................0 0 2,536 2,536
Purchased Services ................................0 0 1,268,668 1,268,668
Weatherization Solutions for Eligible Customers................... 757,748 $0 $33,596 $791,344
Labor/Administrative Expense ................................6,659 0 33,596 40,255
Materials and Equipment ................................6,488 0 0 6,488
Other Expenses ................................................................6,958 0 0 6,958
Purchased Services ................................737,643 0 0 737,643
Residential Total ................................................................ $6,128,874 $175,010 $1,852,341 $8,156,225

Page 10 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Table 2. 2014 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Commercial/Industrial
Building Efficiency ................................................................ $1,212,907 $31,052 $14,315 $1,258,273
Labor/Administrative Expense ................................ 121,949 7,171 14,315 143,435
Other Expense................................................................ 25,871 1,362 0 27,233
Purchased Services ................................ 163,125 8,150 0 171,275
Incentives ................................................................ 901,961 14,370 0 916,331
Custom Efficiency ................................................................ 6,705,219 418,537 49,299 7,173,054
Labor/Administrative Expense ................................ 438,249 25,656 49,299 513,204
Materials and Equipment ................................ 118 6 0 124
Other Expense................................................................ 286,725 6,950 0 293,675
Purchased Services ................................ 791,940 43,459 0 835,399
Incentives ................................................................ 5,188,187 342,465 0 5,530,652
Easy Upgrades ................................................................ 3,020,323 112,623 17,996 3,150,942
Labor/Administrative Expense ................................ 262,053 14,735 17,996 294,784
Other Expense................................................................ 57,907 3,048 0 60,954
Purchased Services ................................ 599,823 31,570 0 631,392
Incentives ................................................................ 2,100,540 63,271 0 2,163,811
FlexPeak Management ................................ 50,964 78,131 1,434,116 1,563,211
Labor/Administrative Expense ................................ 49,576 2,981 7,062 59,620
Other Expense................................................................ 1,387 41 0 1,429
Incentives ................................................................ 0 75,108 1,427,054 1,502,163
Oregon Commercial Audit ................................ 0 9,464 0 9,464
Labor/Administrative Expense ................................ 0 3,902 0 3,902
Other Expense................................................................ 0 737 0 737
Purchased Services ................................ 0 4,825 0 4,825
Commercial/Industrial Total ................................ $ 10,989,412 $649,806 $1,515,726 $13,154,944
Irrigation
................................................................ 2,256,235 144,392 45,880 2,446,507
Labor/Administrative Expense ................................ 183,159 11,002 44,685 238,846
Materials and Equipment ................................ 53 3 0 56
Other Expense................................................................ 31,676 1,667 1,195 34,538
Purchased Services ................................ 2,846 0 0 2,846
Incentives ................................................................ 2,038,500 131,720 0 2,170,220
Irrigation Peak Rewards ................................ 1,374,724 104,995 6,117,494 7,597,213
Labor/Administrative Expense ................................ 37,294 2,242 41,791 81,326
Materials and Equipment ................................ 281 15 0 296
Other Expense................................................................ 31,267 1,646 0 32,913
Purchased Services ................................ 1,305,881 68,967 0 1,374,848
Incentives ................................................................ 32,126 6,075,703 6,107,828
Irrigation Total $ 3,630,958 $249,387 $6,163,374 $10,043,719
Energy Efficiency/Demand Response Total 20,749,245 $1,074,203 $9,531,441 $31,354,889
Market Transformation
NEEA ................................................................ 3,140,621 165,296 0 3,305,917
Purchased Services ................................ 3,140,621 165,296 0 3,305,917
Market Transformation Total ................................ $ 3,140,621 $165,296 $0 $3,305,917

Demand-Side Management 2014 Annual Report Page 11
Supplement 1: Cost-Effectiveness Idaho Power Company
Table 2. 2014 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Other Programs and Activities
Residential
Residential Energy Efficiency Education Initiative................. 394,895 14,844 13,352 423,091
Labor/Administrative Expense ................................ 93,653 5,633 13,340 112,626
Materials and Equipment ................................ 958 50 0 1,008
Other Expense................................................................ 299,961 9,144 12 309,117
Purchased Services ................................ 323 17 0 340
Residential Total ................................................................ $ $394,895 $$14,844 $$13,352 $$423,091
Commercial/Industrial
Commercial Education Initiative ................................ 72,613 3,829 163 76,606
Labor/Administrative Expense ................................ 1,142 68 163 1,373
Other Expense................................................................ 38,744 2,039 0 40,783
Purchased Services ................................ 32,728 1,723 0 34,450
Commercial/Industrial Total ................................ $ 72,613 $3,829 $163 $76,606
Other
Energy Efficiency Direct Program Overhead 427,506 21,711 29,441 478,658
Labor/Administrative Expense ................................ 208,377 12,517 29,441 250,335
Materials and Equipment ................................ 205,435 8,473 0 213,908
Other Expense................................................................ 13,694 721 0 14,415
Local Energy Efficiency Funds ................................ 9,100 0 0 9,100
Incentives ................................................................ 9,100 0 0 9,100
Other Total ................................................................ $ 436,606 $21,711 $29,441 $487,758
Other Programs and Activities Total 904,114 $40,384 $42,956 $987,455
Indirect Program Expense
Residential Overhead ................................ 79,137 5,203 18,251 102,590
Labor/Administrative Expense ................................ 46,523 3,403 18,251 68,177
Materials and Equipment ................................ 16 1 0 17
Other Expense................................................................ 9,374 478 0 9,852
Purchased Services ................................ 23,223 1,321 0 24,544
Commercial/Industrial Overhead ................................ 75,578 6,209 40,612 122,399
Labor/Administrative Expense ................................ 34,185 3,932 40,612 78,728
Materials and Equipment ................................ 21 0 0 21
Other Expense................................................................ 18,234 960 0 19,194
Purchased Services ................................ 23,138 1,317 0 24,456
Energy Efficiency Accounting and Analysis........................... 693,729 39,512 198,119 931,360
Labor/Administrative Expense ................................ 395,862 23,800 195,604 615,265
Materials and Equipment ................................ 26 1 0 27
Other Expense................................................................ 25,580 1,337 2,516 29,432
Purchased Services ................................ 272,263 14,374 0 286,636
Energy Efficiency Advisory Group ................................ 5,702 301 0 6,003
Labor/Administrative Expense ................................ 4,390 232 0 4,622
Other Expense................................................................ 1,312 69 0 1,381
Special Accounting Entries ................................ (92,037) (5,242) 0 (97,280)
Indirect Program Expenses Total ................................ $ 762,109 $45,982 $256,982 $1,065,072
Totals 25,556,089 $1,325,865 $9,831,379 $36,713,333

Page 12 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Table 3. Cost-effectiveness summary by program
2014 Benefit/Cost Tests
Program/Sector
Utility Cost
(UC)
Total Resource
Cost (TRC)
Ratepayer Impact
Measure (RIM)
Participant
Cost (PCT)
Ductless Heat Pump Pilot ................................1.77 0.70 0.62 1.01
Energy Efficient Lighting ................................2.98 1.99 0.59 2.67
Energy House Calls ................................2.16 2.16 0.50 N/A
ENERGY STAR Homes Northwest ................................1.64 0.83 0.61 1.41
Heating & Cooling Efficiency Program ................................3.74 1.09 0.79 1.45
Home Improvement Program ................................4.17 1.51 0.70 2.39
Home Products Program ................................1.94 4.52 0.57 7.28
Rebate Advantage ................................4.39 3.23 0.62 6.21
See ya later, refrigerator 0.86 0.86 0.40 N/A
Student Energy Efficiency Kit ................................2.18 3.02 0.33 N/A
Weatherization Assistance for Qualified Customers 0.51 0.42 0.33 N/A
Weatherization Solutions for Eligible Customers 0.46 0.50 0.31 N/A
Residential Energy Efficiency Sector 1.88 1.51 0.55 2.68
Building Efficiency ................................5.05 2.08 0.98 2.27
Custom Efficiency ................................4.72 2.52 1.35 2.00
Easy Upgrades ................................................................4.08 2.35 0.94 2.85
Commercial/Industrial Energy Efficiency Sector 4.58 2.42 1.17 2.24
Irrigation Efficiency ................................5.67 1.83 1.39 1.63
Irrigation Energy Efficiency Sector ................................ 5.67 1.83 1.39 1.63
Energy Efficiency Portfolio ................................ 3.49 1.89 0.99 2.09

Demand-Side Management 2014 Annual Report Page 13
Idaho Power Company Supplement 1: Cost-Effectiveness
COST-EFFECTIVENESS TABLES BY PROGRAM
Ductless Heat Pump Pilot
Segment: Residential
2014 Program Results

Cost Inputs (net present value [NPV]) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$117,196 Test Benefit Cost Ratio
Program Incentives ................................................................134,250 I Utility Cost Test $443,882 $ 251,446 1.77
Total Utility Cost ................................................................ $251,446 P Total Resource Cost Test 622,102 884,211 0.70
Ratepayer Impact Measure Test 443,882 711,739 0.62
Measure Equipment and Installation (Incremental Participant Cost) $767,015 M Participant Cost Test 772,763 767,015 1.01

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................462,747 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................5,154,668 $403,529 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 40,353 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $443,882 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $460,293 B Nominal (Weighted Average Cost of Capital [WACC]) .............................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $178,221 NEB Minimum NTG Sensitivity ............................................................................N/A
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: Program will be monitored in 2015 for inclusion of additional NEBs.
Demand-Side Management 2014 Annual Report Page 15
Supplement 1: Cost-Effectiveness Idaho Power Company

Year:2014 Program: Ductless Heat Pump Pilot Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross
Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-
Energy Benefit (NEB)
Gross
Incremental Participant Costd Incentive/ Unit
Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Ductless Heat Pump No supplemental fuel screen. Heating zone 2, cooling zone 1.
Zonal Electric 15 2,585.00 $2,327.49 $440.43 $4,285.00 $750.00 $0.253 1.66 0.56 1, 2
No supplemental fuel
screen. Heating zone 3, cooling zone 1.
Zonal Electric 15 292.00 $262.91 $2,435.03 $4,285.00 $750.00 $0.253 0.32 0.62 1, 2
No supplemental fuel screen. Heating zone 2, cooling zone 2.
Zonal Electric 15 2,746.00 $2,472.45 $587.24 $4,285.00 $750.00 $0.253 1.71 0.61 1, 2
No supplemental fuel screen. Heating zone 1, cooling zone 3.
Zonal Electric 15 3,131.00 $2,819.10 $916.07 $4,285.00 $750.00 $0.253 1.83 0.74 1, 2
No supplemental fuel screen. Heating zone 2, cooling zone 3.
Zonal Electric 15 3,016.00 $2,715.55 $744.21 $4,285.00 $750.00 $0.253 1.79 0.69 1, 2
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent conservation adder from the Northwest Power Act.
d Based on 2013–2014 average customer costs for a one indoor/one outdoor unit installation.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives). g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 Regional Technical Forum (RTF). ResHeatingCoolingDuctlessHeatPumpsSF_v2_0.xlsm. 2014.
2 Measure not cost-effective. Measure to be monitored in 2015 for inclusion of additional NEBs.

Page 16 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Energy Efficient Lighting
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$543,975 Test Benefit Cost Ratio
Program Incentives ................................................................1,367,848 I Utility Cost Test $5,698,262 $ 1,910,968 2.98
Add: 2013 costs of give-away CFLs ................................................................ 1,145 Total Resource Cost Test 14,254,970 7,149,572 1.99
Total Utility Cost ................................................................ $1,910,968 P Ratepayer Impact Measure Test 5,698,262 9,594,596 0.59
Measure Equipment and Installation (Incremental Participant Cost) $6,606,452 M Participant Cost Test 17,608,183 6,606,452 2.67

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................12,882,151 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................93,462,422 $5,180,238 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 518,024 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $5,698,262 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $7,683,628 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $8,556,708 NEB Minimum NTG Sensitivity ............................................................................34%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: NEBs include PV of periodic bulb (capital) replacement costs.
Program costs include $1,144.89 in costs from CFLs purchased in 2013 and given away in 2014.

Demand-Side Management 2014 Annual Report Page 17
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Decorative and Mini-base
Efficient Technology: Compact Fluorescent Lamp Type: Decorative and Mini-Base Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp _Lighting 9 9.00 $4.21 $9.81 $1.67 $2.00 $0.042 1.77 6.85 1
-base
Efficient Technology:
Compact Fluorescent Lamp Type: Decorative and Mini-Base Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp ghting 9 16.00 $7.48 $14.11 $0.06 $2.00 $0.042 2.80 29.55 1

Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable
Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp 9 8.00 $3.74 $10.39 $0.06 $2.00 $0.042 1.60 35.79 1

Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 9 8.00 $3.74 $2.89 $0.06 $2.00 $0.042 1.60 16.80 1

Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable Lumen Category: 1440 to 2600 lumens Space Type: ANY
Baseline bulb Lamp 8 14.00 $5.82 $2.83 $0.06 $2.00 $0.042 2.25 13.37 1
Efficient Technology: Compact Fluorescent Lamp Type: Globe Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp 12 6.00 $3.69 $10.90 $0.06 $2.00 $0.042 1.64 46.97 1
Efficient Technology: Compact Fluorescent Lamp Type: Globe Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 12 8.00 $4.92 $17.04 $0.06 $2.00 $0.042 2.11 55.63 1
Page 18 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Reflectors and Outdoor CFL Retailer
Efficient Technology: Compact Fluorescent Lamp Type: Reflectors and Outdoor Lumen Category: 250 to 664lumens Space Type: ANY
Baseline bulb Lamp 8 11.00 $4.57 $23.89 $0.06 $2.00 $0.042 1.86 54.65 1

Efficient Technology: Compact Fluorescent Lamp Type: Reflectors and Outdoor Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 7 18.00 $6.53 $21.61 $0.06 $2.00 $0.042 2.37 34.54 1

Efficient Technology: Compact Fluorescent Lamp Type: Reflectors and Outdoor Lumen Category: 1440 to 2600 lumens Space Type: ANY
Baseline bulb Lamp 5 46.00 $11.68 $38.38 $2.35 $2.00 $0.042 2.97 11.69 1
-Way Efficient Technology: Compact Fluorescent Lamp Type: Three-Way Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 9 13.00 $6.08 $17.06 $4.17 $2.00 $0.042 2.39 4.91 1
-Way
Retailer
Efficient Technology:
Compact Fluorescent Lamp Type: Three-Way Lumen Category: 1440 to 2600 lumens Space Type: ANY
Baseline
bulb
Lamp 8 33.00 $13.71 $30.36 $6.24 $2.00 $0.042 4.05 5.78 1

Efficient Technology: Compact Fluorescent Lamp Type:
General Purpose and Dimmable Lumen Category: 3860 Lumen Space Type: ANY
Baseline bulb Lamp 8 69.00 $28.68 $29.40 $10.12 $2.00 $0.042 5.85 4.46 2

Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable Lumen Category:
4200 Lumen Space Type: ANY
Baseline bulb Lamp 8 87.00 $36.16 $27.75 $12.34 $2.00 $0.042 6.39 4.00 2
Demand-Side Management 2014 Annual Report Page 19
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
General Purpose CFL Give Away
Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 9 8.00 $3.74 $2.89 $— $— $0.042 11.14 19.74 1

Efficient Technology: Compact Fluorescent Lamp Type: General Purpose and Dimmable Lumen Category:1440 to 2600 lumens Space Type: ANY
Baseline bulb Lamp 8 14.00 $5.82 $2.83 $— $— $0.042 9.89 14.71 1
LED
Efficient Technology: LED Lamp Type: General Purpose and Dimmable Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 13 9.00 $5.96 $4.05 $— $— $0.042 15.75 26.48 1
-base
Efficient Technology: LED Lamp Type: Decorative and Mini-Base Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp 12 13.00 $8.00 $10.83 $8.62 $3.00 $0.042 2.26 2.05 1

Efficient Technology: LED
Lamp Type: General Purpose and Dimmable Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp F_Lighting 12 10.00 $6.16 $11.49 $2.56 $3.00 $0.042 1.80 5.92 1

Efficient Technology: LED Lamp Type: General Purpose and
Dimmable Lumen Category: 665 to1439 lumens Space Type: ANY
Baseline bulb Lamp 12 11.00 $6.77 $4.10 $7.21 $3.00 $0.042 1.96 1.42 1
Efficient Technology: LED Lamp Type: Globe Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp 12 8.00 $4.92 $10.90 $4.42 $3.00 $0.042 1.48 3.33 1
Efficient Technology: LED Lamp Type: Globe Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 12 12.00 $7.39 $17.04 $3.84 $3.00 $0.042 2.11 5.62 1
Page 20 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Reflectors and Outdoor LED Retailer
Efficient Technology: LED Lamp Type: Reflectors and Outdoor Lumen Category: 250 to 664 lumens Space Type: ANY
Baseline bulb Lamp 12 16.00 $9.85 $26.76 $16.99 $3.00 $0.042 2.68 2.07 1, 3

Efficient Technology: LED Lamp Type: Reflectors and Outdoor Lumen Category: 665 to 1439 lumens Space Type: ANY
Baseline bulb Lamp 12 27.00 $16.62 $21.56 $11.91 $3.00 $0.042 4.02 2.93 1, 3

Efficient Technology: LED Lamp Type: Reflectors and Outdoor Lumen Category: 1440 to 2600 lumens Space Type: ANY
Baseline bulb Lamp 12 60.00 $36.93 $45.12 $26.43 $3.00 $0.042 6.69 2.83 1, 3
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResLightingCFLandLEDLamps_v3_3.xlsm. 2014.
2 Tetra Tech. Appendix - IPC 2014 EEL Project 20150223.xlsx. 2015.
3 RTF Reflectors and Outdoor LED lamp savings applied to LED Refelctor fixtures. Tetra Tech. IPC PY2014EEL Savings Development Recommendations. 2015.
Demand-Side Management 2014 Annual Report Page 21
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 22 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Energy House Calls
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$198,987 Test Benefit Cost Ratio
Program Incentives ................................................................— I Utility Cost Test $428,207 $ 197,987 2.16
Total Utility Cost ................................................................ $198,987 P Total Resource Cost Test 428,207 197,987 2.16
Ratepayer Impact Measure Test 428,207 856,455 0.50
Measure Equipment and Installation (Incremental Participant Cost) $— M Participant Cost Test N/A N/A N/A

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................579,126 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................7,141,979 $389,279 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 38,928 Participant Cost Test = N/A
Total Electric Savings ................................ $428,207 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $658,458 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................46%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: No participant cost.

Demand-Side Management 2014 Annual Report Page 23
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
PTCS Duct Sealing Single Wide (<= 1000 ft2) Manufactured Home Duct Tightness–PTCS Duct Sealing–
Heating Zone 1 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,496.00 $1,037.34 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft ) Manufactured Home Duct
Tightness–Heating Zone 1 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,433.00 $993.66 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 1 (Electric Heat Pump Heating System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 887.00 $615.06 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 2 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,361.00 $1,637.15 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 2 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,290.00 $1,587.91 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 2 (Electric Heat Pump Heating
System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,664.00 $1,153.84 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 3 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 3,074.00 $2,131.55 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 3 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 3,023.00 $2,096.18 $— $— $— $0.342 2.03 2.03 1
Single Wide (<= 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 3 (Electric Heat Pump Heating System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,324.00 $1,611.49 $— $— $— $0.342 2.03 2.03 1
Page 24 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
PTCS Duct Sealing Other (> 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 1 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,881.00 $1,304.31 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft ) Manufactured Home Duct Tightness –Heating Zone 1 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,799.00 $1,247.45 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 1 (Electric Heat Pump Heating System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 1,093.00 $757.90 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 2 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,898.00 $2,009.51 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 2 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,791.00 $1,935.31 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 2 (Electric Heat Pump Heating System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,022.00 $1,402.08 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft ) Manufactured
Home Duct Tightness–Heating Zone 3 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 3,710.00 $2,572.56 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft ) Manufactured Home Duct Tightness–Heating Zone 3 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage Home ENRes_MH_Heater 18 3,645.00 $2,527.49 $— $— $— $0.342 2.03 2.03 1
Other (> 1000 ft2) Manufactured Home Duct Tightness–Heating Zone 3 (Electric Heat Pump Heating System)
Pre-existing duct leakage Home ENRes_MH_Heater 18 2,813.00 $1,950.57 $— $— $— $0.342 2.03 2.03 1
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses. c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResHeatingCoolingDuctSealingMH_v2_4.xlsm. 2012.

Demand-Side Management 2014 Annual Report Page 25
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 26 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
ENERY STAR® Homes Northwest
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$108,027 Test Benefit Cost Ratio
Program Incentives ................................................................235,250 I Utility Cost Test $563,212 $ 343,277 1.64
Total Utility Cost ................................................................ $343,277 P Total Resource Cost Test 568,541 689,021 0.83
Ratepayer Impact Measure Test 563,212 919,579 0.61
Measure Equipment and Installation (Incremental Participant Cost) $580,994 M Participant Cost Test 816,880 580,994 1.41

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................332,682 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................5,372,633 $512,011 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 51,201 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $563,212 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $576,302 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $5,329 NEB Minimum NTG Sensitivity ............................................................................154%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: 2009 International Energy Conservation Code (IECC) adopted in Idaho in 2011.
Oregon Residential Specialty Code adopted in Oregon in 2011.

Demand-Side Management 2014 Annual Report Page 27
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: ENERGY STAR Homes Northwest Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
ENERGY STAR home
Home in Idaho or Montana with Heat Pump: Heating Zone 1 Cooling Zone 3
Single family home built to International Energy Conservation Code 2009 Code. Adopted 2011.
Home Prog_Energy Star Homes NW 37 3,778.00 $6,086.67 $— $3,999.67 $1,000.00 $0.325 2.73 1.16 1

Home in Oregon with Heat Pump. BOP1
Equipment Upgrade - Heating Zone 1 Cooling Zone 3
New Single Family dwelling up to four
units, permitted in Oregon under the 2011 Oregon Residential Specialty Code.
Home Prog_Energy Star Homes NW 45 3,234.00 $5,755.10 $1,776.25 $3,731.16 $1,000.00 $0.325 2.81 1.57 2

Multifamily—Heat Pump: Heating Zone 1 Cooling Zone 3
Multi-family home built to International Energy Conservation Code 2009 Code. Adopted 2011.
Home Prog_Energy Star Homes NW 36 1,294.00 $2,052.61 $— $2,344.17 $1,000.00 $0.325 1.44 0.74 3,4
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResNewSFEStarWAIDMT_v2_2.xls. 2012.
2 RTF. ResNewSFEStarOR_v3_0.xlsm. 2014.
3 RTF. ResMFEstarHomes2012_v1_1.xlsm. 2012.
4 Measure combination not cost-effective. Will monitor in 2015.
Page 28 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Heating & Cooling Efficiency Program
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$234,664 Test Benefit Cost Ratio
Program Incentives ................................................................127,350 I Utility Cost Test $1,353,986 $ 362,014 3.74
Total Utility Cost ................................................................ $362,014 P Total Resource Cost Test 1,353,986 1,247,560 1.09
Ratepayer Impact Measure Test 1,353,986 1,707,394 0.79
Measure Equipment and Installation (Incremental Participant Cost) $1,012,896 M Participant Cost Test 1,472,730 1,012,896 1.45

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................1,099,464 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................14,300,532 $1,230,896 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 123,090 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $1,353,986 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $1,345,380 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................77%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%

Demand-Side Management 2014 Annual Report Page 29
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Heating & Cooling Efficiency Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Evaporative Cooler Evaporative cooler single family Central A/C Unit ENRes_SF_CAC 12 416.00 $565.50 $— $— $150.00 $0.213 2.37 2.37 1
Evaporative cooler manufactured home Central A/C Unit ENRes_MH_CAC 12 309.00 $462.57 $— $— $150.00 $0.213 2.14 2.14 1
Evaporative cooler multi-family Central A/C Unit ENRes_MF_CAC 12 296.00 $395.54 $— $— $150.00 $0.213 1.86 1.86 1
Open loop water source
heat pump for existing and new construction- 14.00 EER 3.5 COP
Electric
resistance/Oil Propane
Unit ENRes_SF_HeatPump 20 8,927.00 $— $8,360.00 $1,000.00 $0.213 3.55 1.01 2
Open loop water source heat pump –14.00 EER 3.5 COP
Air source heat pump Unit ENRes_SF_HeatPump 20 2,648.00 $3,059.39 $— $8,953.00 $500.00 $0.213 2.88 0.32 2, 3
Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 1
Forced air furnace w/o central A/C
Unit ENRes_SF_Heater 20 5,306.00 $4,158.77 $— $4,223.00 $800.00 $0.213 2.15 0.78 3, 4
Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 2
Forced air furnace w/o central A/C
Unit ENRes_SF_Heater 20 6,961.00 $5,455.94 $— $4,223.00 $800.00 $0.213 2.39 0.96 3, 4
Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 3
Forced air furnace w/o central A/C
Unit ENRes_SF_Heater 20 7,876.00 $6,173.11 $— $4,223.00 $800.00 $0.213 2.49 1.05 4
Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 1 Cooling Zone 3
Forced air furnace with central A/C
Unit ENRes_SF_HeatPump 20 4,380.00 $5,060.48 $— $6,456.00 $800.00 $0.213 2.92 0.68 3, 4
Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 2 Cooling Zone 2
Forced air furnace with central A/C
Unit ENRes_SF_HeatPump 20 6,451.00 $7,453.23 $— $6,456.00 $800.00 $0.213 3.43 0.95 3, 4
Single Family Home HVAC
Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 2 Cooling Zone 3
Forced air
furnace with central A/C
Unit ENRes_SF_HeatPump 20 6,035.00 $6,972.60 $— $6,456.00 $800.00 $0.213 3.34 0.90 3, 4
Page 30 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Heat Pump Conversion Single Family Home HVAC Conversions–Convert to Heat Pump 8.50 HSPF Heating Zone 3 Cooling Zone 1
Forced air furnace with central A/C
Unit ENRes_SF_HeatPump 20 7,634.00 $8,820.02 $— $6,456.00 $800.00 $0.213 3.64 1.09 4
Existing Single Family Home Heat Pump–upgraded to 8.50 HSPF All Climates
Heat pump Unit ENRes_SF_HeatPump 20 2,597.00 $3,000.47 $— $1,905.00 $250.00 $0.213 3.74 1.22 1
Existing Single Family Home Heat Pump–upgraded to 9.0 HSPF/14 SEER Heating Zone 1
Heat pump Unit ENRes_SF_HeatPump 15 128.00 $115.25 $— $59.93 $— $0.213 4.23 1.32 5, 6
Existing Single Family Home Heat Pump–upgraded to 9.0 HSPF/14 SEER Heating Zone 2
Heat pump Unit ENRes_SF_HeatPump 15 116.00 $104.44 $— $59.93 $— $0.213 4.23 1.23 5, 6
Existing Single Family Home Heat Pump–upgraded to 9.0 HSPF/14 SEER Heating Zone 3
Heat pump Unit ENRes_SF_HeatPump 15 115.00 $103.54 $— $59.93 $— $0.213 4.23 1.23 5, 6
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent conservation adder from the Northwest Power Act. d Incremental participant cost prior to customer incentives. Based on 2013-2014 median customer costs and RTF survey data.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 Idaho Power Energy Efficiency Potential Study by EnerNOC Utility Solutions Consulting. IPC Residential LoadMAP.
2 Savings from Ecotope, Inc., heat pump sizing specifications and heat pump measure savings estimates. December 2009.
3 Measure not cost-effective. Measure to be monitored in 2015 . Measure included in the program to increase participation in a cost-effective program and to encourage adoption of higher efficiency equipment.
4 Savings from RTF. Res_SFHPConversion_V2_6.xlsm.2012.
5 RTF. ResHeatingCoolingHeatPumpUpgradeSF_v2_8.xlsm.
6 Customer receive incentive for going to an efficiency of at least an 8.5 HSPF heat pump. Incremental savings claimed for projects with an efficiency greater than a 9.0 HSPF. No additional incentive paid.
Demand-Side Management 2014 Annual Report Page 31
Supplement 1: Cost-Effectiveness Idaho Power Company
This page left blank intentionally.
Page 32 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Home Improvement Program
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$153,319 Test Benefit Cost Ratio
Program Incentives ................................................................171,398 I Utility Cost Test $1,352,970 $ 324,717 4.17
Total Utility Cost ................................................................ $324,717 P Total Resource Cost Test 1,352,970 896,246 1.51
Ratepayer Impact Measure Test 1,352,970 1,929,695 0.70
Measure Equipment and Installation (Incremental Participant Cost) $742,927 M Participant Cost Test 1,776,376 742,927 2.39

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................838,929 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................14,167,441 $1,229,973 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 122,997 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $1,352,970 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $1,604,978 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................42%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%

Demand-Side Management 2014 Annual Report Page 33
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Home Improvement Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Single Family: Attic Insulation
Greater than R38. Electric heat. Program weighted average. Attic Insulation R20 or less
ft2 ENRes_SF_Heater 45 1.09 $1.56 $— $0.65 $0.15 $0.183 4.47 1.84 1

Greater than R30 or fill floor cavity. Electric heat. Program weighted average.
Floor Insulation R5 or less ft ENRes_SF_Heater 45 1.26 $1.81 $— $0.95 $0.50 $0.183 2.47 1.53 1

Greater than R11 or fill wall cavity. Electric heat. Program weighted average.
Wall Insulation R5 or less ft ENRes_SF_Heater 45 1.61 $2.31 $— $0.95 $0.50 $0.183 2.90 1.85 1
U-Factor of 0.30 or lower. Electric heat. Program weighted average.
Single pane metal, Single pane wood or double pane metal.
ft2 ENRes_SF_Heater 45 14.99 $21.49 $— $21.75 $2.50 $0.183 4.10 0.88 1, 2, 3
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent conservation adder from the Northwest Power Act.
d Based on 2014 median customer costs.
e Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + 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. ResSFWx_v2_5_IdahoPower_withCAC_ByCoolingZone.xlsm. 2011.
2 RTF. Incremental costs from ResSFWx_v2_5_IdahoPower_withCAC_ByCoolingZone.xlsm. 2011.
3 Measure not cost-effective. Will monitor in 2015.

Page 34 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Home Products Program
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$80,213 Test Benefit Cost Ratio
Program Incentives ................................................................146,963 I Utility Cost Test $441,360 $ 227,176 1.94
Total Utility Cost ................................................................ $227,176 P Total Resource Cost Test 1,366,024 302,289 4.52
Ratepayer Impact Measure Test 441,360 772,488 0.57
Measure Equipment and Installation (Incremental Participant Cost) $222,076 M Participant Cost Test 1,616,939 222,076 7.28

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................652,129 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................6,317,074 $401,237 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 40,124 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $441,360 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $545,312 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $200 NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $924,464 NEB Minimum NTG Sensitivity ............................................................................51%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: One-time upstream clothes washer promotion for high-efficiency clothes washers with modified energy factor of 3.2 or higher and water factor of 2.9 or lower.
NEBs include NPV of avoided gas, water, and detergent savings for ENERGY STAR® clothes washers. Non-utility incentive includes $50 per clothes washer incentive from upstream promotion.
NEBs also include the NPV of water savings from low-flow showerheads.
Demand-Side Management 2014 Annual Report Page 35
Supplement 1: Cost-Effectiveness Idaho Power Company

Year:2014 Program: Home Products Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Clothes Washer ENERGY STAR clothes washer MEF of 3.2 or higher and WF of 2.9 or lower, Any DHW, Any Dryer
Baseline clothes washers
ENRes_SF_Washer 14 121.00 $94.60 $592.03 $275.94 $50.00 $0.012 1.84 2.48 1
ENERGY STAR
Refrigerator–Bottom Freezer w/Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 16.00 $14.16 $— $6.66 $30.00 $0.946 0.31 0.65 2
ENERGY STAR Refrigerator–Bottom Freezer w/o Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 18.00 $15.93 $— $6.38 $30.00 $0.946 0.34 0.68 2, 3
ENERGY STAR Refrigerator–Side-by-Side w/Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 24.00 $21.24 $— $20.19 $30.00 $0.946 0.40 0.50 2, 3
ENERGY STAR Refrigerator–Side-by-Side w/o Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 21.00 $18.58 $— $25.31 $30.00 $0.946 0.37 0.41 2, 3
ENERGY STAR Refrigerator - Top Freezer w/Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 26.00 $23.01 $— $11.20 $30.00 $0.946 0.42 0.64 2, 3
ENERGY STAR Refrigerator–Top Freezer w/o Ice thru door
Baseline refrigerator ENRes_SF_Refrigerator 17 50.00 $44.25 $— $18.67 $30.00 $0.946 0.57 0.67 2, 3
ENERGY STAR Freezer (no tiers)–Chest, Any Defrost
Baseline freezer ENRes_SF_Freezer 22 29.00 $33.34 $— $3.48 $20.00 $0.946 0.70 1.08 3, 4
ENERGY STAR Freezer (no tiers)–Upright, Automatic Defrost
Baseline freezer ENRes_SF_Freezer 22 56.00 $64.39 $— $5.92 $20.00 $0.946 0.88 1.09 3, 4
ENERGY STAR Freezer (no tiers)–Upright, Manual Defrost
Baseline freezer ENRes_SF_Freezer 22 28.00 $32.19 $— $2.96 $20.00 $0.946 0.69 1.09 3, 4
-flow Low-flow showerhead 2.0 gpm Any Shower Any Water Heating Retail
Showerhead 2.2 gpm or higher
ENRes_SF_WtrHtr 10 66.78 $34.79 $108.76 $28.20 $7.00 $0.012 4.46 4.95 5
-flow Low-flow showerhead 1.75 gpm Any Shower Any Water Heating Retail
Showerhead 2.2 gpm or higher
ENRes_SF_WtrHtr 10 99.77 $51.98 $159.59 $28.20 $7.00 $0.012 6.34 7.20 5
Page 36 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Low-flow Low-flow showerhead 1.5 gpm Any Shower Any Water Heating Retail
Showerhead 2.2 gpm or higher
howerhead ENRes_SF_WtrHtr 10 129.12 $67.27 $202.92 $28.20 $7.00 $0.012 7.87 9.08 5
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals. f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResClothesWasherSF_v4.0.xls. Any DHW, Any Dryer. 2013. Adjusted savings by changing Electric Water Heating saturation from 55% to 52% to match IPC mix.
2 RTF. ResRefrigerator_v3_1.xls. 2013.
3 Measure not cost-effective. Will be removed from the program as a mail-in rebate measure.
4 RTF. ResFreezer_v2_2.xlsm. 2012.
5 RTF. ResShowerheads_v2_1.xlsm. 2011. Adjusted savings by changing Electric Water Heating saturation from 64% to 52% to match IPC mix.
Demand-Side Management 2014 Annual Report Page 37
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 38 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Rebate Advantage
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$19,231 Test Benefit Cost Ratio
Program Incentives 44,000 I Utility Cost Test $277,443 $ 63,231 4.39
Total Utility Cost ................................................................ $63,231 P Total Resource Cost Test 289,729 89,699 3.23
Ratepayer Impact Measure Test 277,443 444,768 0.62
Measure Equipment and Installation (Incremental Participant Cost) $70,468 M Participant Cost Test 437,823 70,468 6.21

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG P
2014 Annual Gross Energy (kWh) ................................269,643 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................3,872,902 $252,221 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 25,222 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $277,443 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $381,538 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $12,285 NEB Minimum NTG Sensitivity ............................................................................24%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%

Demand-Side Management 2014 Annual Report Page 39
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
ENERGY STAR® manufactured home
New ENERGY STAR Manufactured Home with Electric FAF: Heating Zone 1
Manufactured home built to Housing and Urban Development (HUD) code.
Home ENRes_MH_Heater 26 5,420.00 $5,335.39 $277.29 $1,617.53 $1,000.00 $0.071 3.85 2.80 1

New ENERGY STAR
Manufactured Home with Electric FAF: Heating Zone 2
Manufactured
home built to HUD code.
Home ENRes_MH_Heater 27 6,847.00 $6,951.21 $283.62 $1,617.53 $1,000.00 $0.071 4.68 3.44 1

New ENERGY STAR Manufactured Home with Electric FAF: Heating Zone 3
Manufactured home built to HUD code.
Home ENRes_MH_Heater 27 8,057.00 $8,179.62 $283.62 $1,617.53 $1,000.00 $0.071 5.20 3.87 1

New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 1 Cooling Zone 3
Manufactured home built to HUD code.
Home 23 3,254.00 $4,219.56 $256.87 $1,617.53 $1,000.00 $0.071 3.43 2.42 1
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. NewMH_EStar_EcoRated_v1_3.xls. 2013.

Page 40 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
See ya later, refrigerator®
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$480,231 Test Benefit Cost Ratio
Program Incentives 95,820 I Utility Cost Test $492,603 $ 576,051 0.86
Total Utility Cost ................................................................ $576,051 P Total Resource Cost Test 492,603 576,051 0.86
Ratepayer Impact Measure Test 492,603 1,219,997 0.40
Measure Equipment and Installation (Incremental Participant Cost) $— M Participant Cost Test N/A N/A N/A

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................1,390,760 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................8,029,470 $447,821 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 44,782 Participant Cost Test N/A
Total Electric Savings ................................ $492,603 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $643,946 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................117%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: No participant costs.
Program to be modified in 2015 to increase cost-effectiveness.

Demand-Side Management 2014 Annual Report Page 41
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: See ya later, refrigerator Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Freezer Recycling 5 478.00 $136.00 $— $— $30.00 $0.345 0.70 0.70 1, 2
7 424.00 $165.41 $— $— $30.00 $0.345 0.94 0.94 1, 2
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. ResFridgeFreezeDecommissioning_v2.5.xlsm. 2012.
2 Measure not cost-effective. Program modified in 2015 to increase cost-effectiveness.

Page 42 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Student Energy Efficiency Kit

Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$209,630 Test Benefit Cost Ratio
Program Incentives — I Utility Cost Test $456,243 $ 209,630 2.18
Total Utility Cost ................................................................ $209,630 P Total Resource Cost Test 633,386 209,630 3.02
Ratepayer Impact Measure Test 456,243 1,371,978 0.33
Measure Equipment and Installation (Incremental Participant Cost) $— M Participant Cost Test N/A N/A N/A

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................1,491,225 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................7,254,382 $414,767 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 41,477 Participant Cost Test N/A
Total Electric Savings ................................ $456,243 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $1,162,348 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $177,143 NEB Minimum NTG Sensitivity ............................................................................46%
Average Customer Segment Rate/kWh .......................................................$0.086
Line Losses .................................................................................................9.60%
Notes: Energy savings as reported by National Energy Foundation for the fall 2013 kits and by Resource Action Plan for the spring 2014 kits. Non-energy benefits include NPV of avoided gas.
Direct costs for the fall 2013 and spring 2014 kit offerings used for program costs.

Demand-Side Management 2014 Annual Report Page 43
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 44 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Weatherization Assistance for Qualified Customers
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$192,753 Test Benefit Cost Ratio
CAP Agency Payments ................................................................1,127,359 Utility Cost Test .............................$702,511 $ 1,383,137 0.51
Total Program Expenses ................................................................ $1,320,112 Total Resource Cost Test .............. 563,263 2,060,133 0.42
Add: 2013 Evaluations Expenses (Amortized Year 2) ................................24,044 Ratepayer Impact Measure Test ... 702,511 2,138,449 0.33
Total Utility Cost ................................................................ $1,344,156 P Participant Cost Test ..................... N/A N/A N/A

Idaho Power Indirect Overhead Expense Allocation—2.9% ................................ $38,981 OH
Additional State Funding ................................................................ 676,996 M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................533,800 Total Resource Cost Test = (S + NUI + NEB) * NTG
NPV Cumulative Energy (kWh) ................................7,661,240 $638,646 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 63,865 Participant Cost Test N/A N/A
Total Electric Savings ................................ $705,511 S

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ................................ $755,313 B Discount Rate
Nominal (WACC) ................................................................6.77%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................3.66%
Non-Utility Rebates/Incentives ................................ $— NUI Escalation Rate ................................................................3.00%
Non-Energy Benefits ................................................................ Net-to-Gross (NTG) ................................................................100%
Health and Safety ................................ 127,177 Minimum NTG Sensitivity ................................................................239%
Repair ................................................................ 33,576 Average Customer Segment Rate/kWh ................................$0.086
Other ................................................................ — Line Losses ................................................................................................9.60%
Non-Energy Benefits Total ................................ $160,753 NEB
Notes: Savings from the billing analysis of 2012 weatherization projects: single family/multi-family/townhomes = 1,551 kWh/per home, manufactured homes = 2,568 kWh/home, non-profits = 1.03 kWh/heated square foot.
Program cost-effectiveness incorporated Idaho Public Utilities Commission (IPUC) staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Claimed 100% of savings; increased NTG to 100%; added a 10% conservation preference adder; health, safety, and repair non-energy benefits; amortized evaluation expenses over a three-year period; and allocation of indirect overhead expenses.
No customer participant costs. Costs shown are from the DOE state weatherization assistance program.
Demand-Side Management 2014 Annual Report Page 45
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 46 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Weatherization Solutions for Eligible Customers
Segment: Residential
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$129,140 Test Benefit Cost Ratio
Weatherization LLC Payments ................................................................662,204 Utility Cost Test .............................$382,875 $ 839,035 0.46
Total Program Expenses ................................................................ $791,344 Total Resource Cost Test .............. 420,373 839,035 0.50
Add: 2013 Evaluations Expenses (Amortized Year 2) ................................24,044 Ratepayer Impact Measure Test ... 382,875 1,250,688 0.31
Total Utility Cost ................................................................ $815,389 P Participant Cost Test ..................... N/A N/A N/A

Idaho Power Indirect Overhead Expense Allocation—2.9% ................................$23,646 OH
Additional State Funding ................................................................ — M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................290,926 Total Resource Cost Test = (S + NUI + NEB) * NTG
NPV Cumulative Energy (kWh) ................................4,175,448 $348,068 Ratepayer Impact Measure Test = S * NTG NTG)
10% Credit (Northwest Power Act) ................................ 34,807 Participant Cost Test N/A N/A
Total Electric Savings ................................ $382,875 S

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ................................ $411,653 B Discount Rate
Nominal (WACC) ................................................................6.77%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................3.66%
Non-Utility Rebates/Incentives ................................ $— NUI Escalation Rate ................................................................3.00%
Non-Energy Benefits ................................................................ Net-to-Gross (NTG) ................................................................100%
Health and Safety ................................ 33,807 Minimum NTG Sensitivity ................................................................219%
Repair ................................................................ 3,692 Average Customer Segment Rate/kWh ................................$0.086
Other ................................................................ — Line Losses ................................................................................................9.60%
Non-Energy Benefits Total ................................ $37,498 NEB
Notes: Savings from the billing analysis of the 2012 weatherization projects. Single family/multi-family/townhomes = 2,108 kWh/per home. Manufactured homes = 3,426 kWh/home.
Program cost-effectiveness incorporated IPUC staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Claimed 100% of savings; increased NTG to 100%; added a 10% conservation preference adder; health, safety, and repair non-energy benefits, and allocation of indirect overhead expenses.
No customer participant costs.
Demand-Side Management 2014 Annual Report Page 47
Supplement 1: Cost-Effectiveness Idaho Power Company
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Page 48 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Building Efficiency
Segment: Commercial
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$341,943 Test Benefit Cost Ratio
Program Incentives 916,331 I Utility Cost Test $6,348,187 $ 1,258,273 5.05
Total Utility Cost ................................................................ $1,258,273 P Total Resource Cost Test 6,348,187 3,056,492 2.08
Ratepayer Impact Measure Test 6,348,187 6,491,358 0.98
Measure Equipment and Installation (Incremental Participant Cost) $2,714,549 M Participant Cost Test 6,149,415 2,714,549 2.27

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................9,458,059 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................91,619,094 $5,771,079 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 577,108 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $6,348,187 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $5,233,084 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................28%
Average Customer Segment Rate/kWh .......................................................$0.057
Line Losses .................................................................................................9.60%

Demand-Side Management 2014 Annual Report Page 49
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Building Efficiency Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing End Use
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Lighting Interior Light Load Reduction. Part A: 10-19.9% below code.
Code standards
2 ENComm_InsLt 14 0.51 $0.40 $— $0.26 $0.10 $0.036 3.41 1.45 1
Interior Light Load Reduction. Part B: 20-29.9% below code.
Code standards ENComm_InsLt 14 1.03 $0.82 $— $0.51 $0.20 $0.036 3.44 1.49 1
Interior Light Load Reduction. Part C: Equal to or greater than 30% below code.
Code standards ENComm_InsLt 14 2.33 $1.84 $— $0.89 $0.30 $0.036 4.80 1.89 1
Exterior Light Load Reduction. Minimum of 15% below code.
Code standards IPC_Outdoor Lighting 15 4,059.00 $2,244.40 $— $168.00 $160.00 $0.036 7.33 7.14 1
Daylight Photo Controls Code standards ENComm_InsLt 14 0.94 $0.74 $— $0.91 $0.25 $0.036 2.62 0.79 1, 2
Occupancy sensors Code standards ENComm_InsLt 8 366.00 $172.43 $— $38.26 $25.00 $0.036 4.52 3.35 1
High Efficiency Exit Signs Code standards IPC_8760 16 28.00 $22.56 $— $10.83 $7.50 $0.036 2.65 1.91 1
6-11 ton AC unit that meets CEE Tier 1 12-19 ton AC unit that meets CEE Tier 1 20-25 ton AC unit that meets CEE Tier 1 (≥ 65,000 Btu/hr & ≤ 300,000 Btu/hr)
Code standards ENComm_Cooling 15 40.30 $43.93 $— $36.18 $30.00 $0.036 1.40 1.17 3
0-5 ton AC unit that meets CEE Tier 2 6-11 ton AC unit that meets CEE Tier 2 12-19 ton AC unit that meets CEE Tier 2 20-25 ton AC unit that meets CEE Tier 2 (≤ 300,000 Btu/hr)
Code standards ENComm_Cooling 15 90.16 $98.27 $— $115.37 $75.00 $0.036 1.26 0.83 3, 4
0-5 ton Heat Pump (HP) unit that meets CEE Tier 1 6-11 ton HP unit that meets CEE Tier 1 12-19 ton HP unit that meets CEE Tier 1 20-25 ton HP unit that meets CEE Tier 1 (≤ 300,000 Btu/hr)
Code standards ENComm_Cooling 15 27.25 $29.70 $— $31.83 $30.00 $0.036 0.96 0.91 3, 4
Page 50 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing End Use
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
A/C 6-11 ton AC VRF unit that meets CEE Tier 1 12-19 ton AC VRF unit that meets CEE Tier 1 20-25 ton AC VRF unit that meets CEE Tier 1
(≥ 65,000 Btu/hr & ≤ 300,000 Btu/hr)
Code standards ENComm_Cooling 15 132.60 $144.53 $— $115.37 $75.00 $0.036 1.81 1.20 3
6-11 ton HP VRF unit that meets CEE Tier 1 12-19 ton HP VRF unit that meets CEE Tier 1 20-25 ton HP VRF unit that meets CEE Tier 1 (≥ 65,000 Btu/hr & ≤ 300,000 Btu/hr)
Code standards ENComm_Cooling 15 332.91 $362.86 $— $95.30 $75.00 $0.036 4.17 3.38 3
Air-cooled chiller condenser, IPLV 14.0 EER or higher
Code standards ENComm_Cooling 20 472.44 $653.55 $— $86.12 $80.00 $0.036 6.74 6.34 1
Water-cooled chiller electronically operated, reciprocating and positive displacement
Code standards ENComm_Cooling 20 212.96 $294.60 $— $38.82 $40.00 $0.036 6.18 6.34 5
Airside economizer Code standards ENComm_Cooling 15 344.00 $374.95 $— $81.36 $75.00 $0.036 4.29 4.00 1
Direct evaporative cooler Code standards ENComm_Cooling 15 399.00 $434.90 $— $364.00 $200.00 $0.036 2.03 1.15 1
Reflective roof
treatment
Code
standards
roof

ENComm_Cooling 15 0.12 $0.13 $— $0.05 $0.05 $0.036 2.33 2.33 1
Energy Management System (EMS) controls. Part A: 2 strategies
Code standards ENComm_Cooling 15 454.00 $494.84 $— $162.49 $70.00 $0.036 5.73 2.77 1
EMS controls. Part B: 3 strategies Code standards ENComm_Cooling 15 496.00 $540.62 $— $162.49 $80.00 $0.036 5.52 3.00 6
EMS controls. Part C: 4 strategies Code standards ENComm_Cooling 15 498.95 $543.84 $— $162.49 $90.00 $0.036 5.04 3.01 1
EMS controls. Part D: 5 strategies Code standards ENComm_Cooling 15 511.75 $557.79 $— $162.49 $100.00 $0.036 4.71 3.08 6
Guest room energy management system Code standards ENComm_HVAC 11 384.00 $272.92 $— $57.50 $50.00 $0.036 4.28 3.83 1
Part A. Variable speed drive on HVAC system applications: -chilled water pumps -condenser water pumps -cooling tower fans
Code standards ENComm_HVAC 15 268.00 $248.78 $— $165.33 $60.00 $0.036 3.57 1.42 1
Demand-Side Management 2014 Annual Report Page 51
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing End Use
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog
Controls Part B. Variable speed drive on HVAC system applications: -supply -return -outside air
-make-up air -hot water pumps
Code standards ENComm_HVAC 15 996.00 $924.57 $— $142.05 $100.00 $0.036 6.81 5.20 1

Efficient Laundry Machines (electric) Code standards ENComm_WtrHtr 10 756.00 $411.96 $— $200.00 $125.00 $0.036 2.71 1.81 1

ENERGY STAR® undercounter (residential style) dishwasher
Code standards ENComm_Misc 12 2,210.00 $1,467.71 $251.95 $232.00 $200.00 $0.036 5.25 5.52 7

ENERGY STAR commercial dishwasher Code standards ENComm_Misc 12 5,561.00 $3,693.19 $679.51 $3,978.00 $500.00 $0.036 5.27 1.05 7
Refrigeration head pressure controls Code standards ENComm_Refrigeration 16 225.00 $191.49 $— $166.60 $40.00 $0.036 3.98 1.10 1
Refrigeration floating suction controls Code standards ENComm_Refrigeration 16 77.00 $65.53 $— $53.75 $10.00 $0.036 5.13 1.16 1
Efficient refrigeration condensers Code standards
ENComm_Refrigeration 15 114.00 $91.90 $— $35.00 $20.00 $0.036 3.81 2.35 1
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals. f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 Idaho Power Technical Reference Manual (TRM) prepared by ADM Associates, Inc. 2015.
2 Measure not cost-effective. Measure to remain in the program due to unquantifiable non-energy benefits.
3 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Weighted average of 6-25 ton units.
4 Measure not cost-effective. Measure to be monitored in 2015 to adjust weighted average. Measure included in the program to increase participation in a cost-effective program and to encourage adoption of higher efficiency equipment.
5 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Averaged water cooled chillers.
6 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Calculated from TRM spreadsheets.
7 Idaho Power TRM prepared by ADM Associates, Inc. 2015. NEBs from water savings from RTF. ComDishwasher_v1_2.xlsm. 2012.

Page 52 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Custom Efficiency
Segment: Industrial
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$1,642,402 Test Benefit Cost Ratio
Program Incentives 5,530,652 I Utility Cost Test $33,824,952 $ 7,173,054 4.72
Total Utility Cost ................................................................ $7,173,054 P Total Resource Cost Test 33,824,952 13,409,922 2.52
Ratepayer Impact Measure Test 33,824,952 25,119,430 1.35
Measure Equipment and Installation (Incremental Participant Cost) $11,767,520 M Participant Cost Test 23,477,027 11,767,520 2.00

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................50,363,052 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................488,278,575 $30,749,957 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 3,074,996 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $33,824,952 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $17,946,375 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................26%
Average Customer Segment Rate/kWh .......................................................$0.037
Line Losses .................................................................................................9.60%
Notes: Energy savings are unique by project and are reviewed by Idaho Power engineering staff or third-party consultants. Each project must complete a certification inspection.
Green Rewind initiative is available to agricultural, commercial, and industrial customers. Commercial and industrial motor rewinds are paid under Custom Efficiency.

Demand-Side Management 2014 Annual Report Page 53
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Custom Efficiency—Green Motors Market Segment: Industrial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Green Motors Program Rewind Standard rewind practice Motor 8 601.00 $272.56 $— $157.66 $30.00 $0.050 4.54 1.45 1
Standard rewind practice Motor 8 804.00 $364.62 $— $175.90 $40.00 $0.050 4.55 1.69 1
Standard rewind practice Motor 8 1,052.00 $477.10 $— $200.98 $50.00 $0.050 4.65 1.88 1
Standard rewind practice Motor 8 1,133.00 $513.83 $— $220.74 $60.00 $0.050 4.40 1.85 1
Standard rewind practice Motor 8 1,319.00 $598.18 $— $269.75 $80.00 $0.050 4.10 1.78 1
Standard rewind practice Motor 8 1,418.00 $643.08 $— $298.62 $100.00 $0.050 3.76 1.74 1
Standard rewind practice Motor 9 1,476.00 $751.67 $— $352.19 $120.00 $0.050 3.88 1.76 1
5HP Standard rewind practice Motor 9 1,519.00 $773.57 $— $380.68 $150.00 $0.050 3.42 1.69 1
Standard rewind practice Motor 9 2,005.00 $1,021.07 $— $472.24 $200.00 $0.050 3.40 1.78 1
Standard rewind practice Motor 8 2,598.00 $1,178.23 $— $530.37 $250.00 $0.050 3.10 1.78 1
Standard rewind practice Motor 8 3,089.00 $1,400.90 $— $590.78 $300.00 $0.050 3.08 1.88 1
Standard rewind practice Motor 8 4,088.00 $1,853.96 $— $711.22 $400.00 $0.050 3.07 2.02 1
Standard rewind practice Motor 9 4,972.00 $2,532.05 $— $914.10 $500.00 $0.050 3.38 2.18 1
Standard rewind practice Motor 9 5,935.00 $3,022.47 $— $923.98 $600.00 $0.050 3.37 2.48 1
Standard rewind practice Motor 9 6,919.00 $3,523.59 $— $968.43 $700.00 $0.050 3.37 2.68 1
Standard rewind practice Motor 9 7,848.00 $3,996.69 $— $1,081.64 $800.00 $0.050 3.35 2.71 1
Standard rewind practice Motor 9 8,811.00 $4,487.11 $— $1,182.32 $900.00 $0.050 3.35 2.76 1
Standard rewind practice Motor 9 9,804.00 $4,992.81 $— $1,277.31 $1,000.00 $0.050 3.35 2.82 1
Standard rewind practice Motor 7 14,689.00 $5,833.73 $— $1,882.27 $1,200.00 $0.050 3.02 2.23 1
Standard rewind practice Motor 7 17,065.00 $6,777.36 $— $2,053.56 $1,400.00 $0.050 3.01 2.33 1
Page 54 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Green Motors Program Rewind Standard rewind practice Motor 7 19,461.00 $7,728.93 $— $2,278.48 $1,600.00 $0.050 3.00 2.38 1
Standard rewind practice Motor 7 21,847.00 $8,676.53 $— $2,511.92 $1,800.00 $0.050 3.00 2.41 1
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. IndGreenMotorRewind_v2_0.xlsm. 2013.

Demand-Side Management 2014 Annual Report Page 55
Supplement 1: Cost-Effectiveness Idaho Power Company
This page left blank intentionally.
Page 56 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Easy Upgrades
Segment: Commercial
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$987,131 Test Benefit Cost Ratio
Program Incentives 2,163,811 I Utility Cost Test $12,840,408 $ 3,150,942 4.08
Total Utility Cost ................................................................ $3,150,942 P Total Resource Cost Test 12,840,408 5,453,380 2.35
Ratepayer Impact Measure Test 12,840,408 13,729,083 0.94
Measure Equipment and Installation (Incremental Participant Cost) $4,466,249 M Participant Cost Test 12,741,953 4,466,249 2.85

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................19,118,494 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................185,357,135 $11,673,098 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 1,167,310 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $12,840,408 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $10,578,142 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $— NEB Minimum NTG Sensitivity ............................................................................30%
Average Customer Segment Rate/kWh .......................................................$0.057
Line Losses .................................................................................................9.60%
Notes: Measure inputs from Evergreen Consulting Group or the Technical Reference Manual prepared by ADM Associates, Inc. unless otherwise noted.

Demand-Side Management 2014 Annual Report Page 57
Supplement 1: Cost-Effectiveness Idaho Power Company
Year:2014 Program: Easy Upgrades Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Standard/High Performance T8 Fluorescents
4-foot T8 4-foot T12 11 180.28 $115.23 $— $61.15 $33.21 $0.052 2.71 1.63 1
6-foot T8 6-foot T12 11 332.20 $212.34 $— $76.03 $16.00 $0.052 6.38 2.28 1
8-foot T8 8-foot T12 11 262.06 $167.51 $— $80.56 $22.75 $0.052 4.60 1.78 1

4-foot & 8-foot T8 8-foot T12HO 11 564.84 $361.05 $— $75.36 $46.18 $0.052 4.78 3.45 1
-HO) 4-foot T5 4-foot T12 11 156.85 $100.26 $— $76.21 $36.18 $0.052 2.26 1.19 1
New Fixture 4-foot T8/T5 Fixture using > 200 input watts 11 1,194.00 $763.20 $— $216.24 $137.72 $0.052 3.82 2.74 1

Reduced wattage T8/T5 re-lamp 8 130.58 $61.52 $— $23.07 $1.00 $0.052 7.90 2.06 1
Permanent Fixture Removal 8 878.14 $413.71 $— $35.78 $22.73 $0.052 6.05 5.08 1
-in -
Screw-in CFLs/cold-cathode Fixture using > 40 input watts 6 164.23 $57.99 $— $33.23 $5.08 $0.052 4.26 1.39 1
Hardwired CFLs Fixture using > 90 input watts 6 366.94 $129.57 $— $94.75 $50.00 $0.052 1.88 1.14 1

LED Replacement Lamps Fixture using > 20 input watts 12 154.10 $106.58 $— $48.66 $24.25 $0.052 3.30 1.88 1

Pulse Start/Electronic Metal Halide Fixture using > 170 input watts 11 1,091.70 $697.81 $— $153.66 $105.55 $0.052 4.30 3.32 1
LED Exit Sign Exit sign using ≥ 18 watts 12 230.68 $144.62 $— $68.69 $40.00 $0.052 2.78 1.79 1
Lighting Controls Manual controls 10 280.14 $163.86 $— $111.74 $49.02 $0.052 2.58 1.30 1

4-foot T8 4-foot T12 11 166.42 $68.76 $— $61.15 $13.80 $0.052 3.06 0.99 1, 2
6-foot T8 6-foot T12 11 386.42 $159.66 $— $76.03 $14.00 $0.052 4.68 1.66 1
Page 58 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Standard T8 Fluorescents 8-foot T8 8-foot T12 11 303.92 $125.57 $— $80.56 $19.50 $0.052 3.56 1.30 1

4-foot & 8-foot T8 8-foot T12HO 11 913.16 $377.30 $— $75.36 $21.48 $0.052 5.47 3.07 1
-HO) 4-foot T5 4-foot T12 11 181.22 $74.88 $— $76.21 $20.47 $0.052 2.50 0.87 1, 2
New Fixture 4-foot T8/T5 Fixture using > 200 input watts 11 1,643.60 $679.10 $— $216.24 $102.71 $0.052 3.61 2.25 1
Permanent Fixture Removal 8 1,018.40 $302.47 $— $35.78 $14.09 $0.052 4.51 3.41 1
-in -
Screw-in CFLs/cold-cathode Fixture using > 40 input watts 6 190.46 $41.20 $— $33.23 $5.08 $0.052 2.75 0.96 1, 2
Hardwired CFLs Fixture using > 90 input watts 6 425.55 $92.05 $— $94.75 $35.00 $0.052 1.61 0.79 1, 2

LED Replacement Lamps Fixture using > 20 input watts 12 178.71 $80.31 $— $48.66 $19.25 $0.052 2.81 1.39 1

Pulse Start/Electronic Metal Halide Fixture using > 170 input watts 11 1,265.40 $522.83 $— $153.66 $45.68 $0.052 4.69 2.38 1
Lighting Controls Manual controls 10 255.65 $96.08 $— $111.74 $45.50 $0.052 1.63 0.77 1, 2
Case # 1 - T8 fluorescent
lighting and electronic ballast (per lamp)
Case # 1 - T12
fluorescent lighting
6 309.31 $104.46 $— $44.70 $15.00 $0.052 3.36 1.72 3
Case # 2 - LED display case lighting (per linear foot)
Case # 2 - T12 fluorescent lighting 8 111.25 $50.21 $17.64 $43.63 $15.00 $0.052 2.42 1.37 4
Case # 3 - LED display case lighting (per linear foot)
Case #3 - T8 fluorescent lighting 8 77.75 $35.09 $16.36 $45.33 $10.00 $0.052 2.50 1.04 5
6-11 ton AC unit that meets CEE Tier 1
12-19 ton AC unit that meets CEE Tier 1 20-25 ton AC unit that meets CEE Tier 1
Standard 6-11 ton AC unit
Standard 12-19 ton AC unit Standard 20-25 ton AC unit
15 40.30 $43.93 $— $36.18 $30.00 $0.052 1.37 1.15 6
Demand-Side Management 2014 Annual Report Page 59
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
AC Units 1-5 ton AC unit that meets CEE Tier 2 6-11 ton AC unit that meets CEE Tier 2 12-19 ton AC unit that
meets CEE Tier 2 20-25 ton AC unit that meets CEE Tier 2
Standard 1-5 ton AC unit Standard 6-11 ton AC unit Standard 12-19
ton AC unit Standard 20-25 ton AC unit
15 90.16 $98.27 $— $115.37 $75.00 $0.052 1.23 0.82 2, 6
6-11 ton AC VRF unit that meets CEE Tier 1 12-19 ton AC VRF unit that meets CEE Tier 1 20-25 ton AC VRF unit that meets CEE Tier 1
Standard 6-11 ton AC VRF unit Standard 12-19 ton AC VRF unit Standard 20-25 ton AC VRF unit
15 132.60 $144.53 $— $115.37 $75.00 $0.052 1.76 1.18 6
1-5 ton HP unit that meets CEE Tier 1 6-11 ton HP unit that meets CEE Tier 1 12-19 ton HP unit that meets CEE Tier 1 20-25 ton HP unit that meets CEE Tier 1
Standard 1-5 ton HP unit Standard 6-11 ton HP unit Standard 12-19 ton HP unit Standard 20-25 ton HP unit
15 27.25 $29.70 $— $31.83 $30.00 $0.052 0.95 0.89 2, 6
6-11 ton HP VRF unit that meets CEE Tier 1 12-19 ton HP VRF unit that meets CEE Tier 1 20-25 ton HP VRF unit that meets CEE Tier 1
Standard 6-11 ton HP VRF unit Standard 12-19 ton HP VRF unit Standard 20-25 ton HP VRF unit
15 332.91 $362.86 $— $95.30 $75.00 $0.052 3.93 3.22 6
Air-cooled chiller condenser, IPLV 14.0 EER or higher
Standard air-cooled chiller 20 472.44 $653.55 $— $86.12 $80.00 $0.052 6.25 5.90 7
Water-cooled chiller electronically operated, reciprocating and positive displacement
Standard water-cooled chiller 20 212.96 $294.60 $— $38.82 $40.00 $0.052 5.77 5.90 8
Airside economizer control addition No prior control of 15 634.00 $691.04 $— $155.01 $100.00 $0.052 5.20 3.68 7
Airside economizer control repair Non-functional economizer 15 634.00 $691.04 $— $73.65 $50.00 $0.052 8.33 6.48 7
-
Direct evaporative cooler Replacing standard AC unit 15 399.00 $434.90 $— $364.00 $200.00 $0.052 1.97 1.13 7
EMS controls with 2 strategies Proposed strategy not existing (retrofit system) oling 15 918.00 $1,000.59 $— $197.98 $125.00 $0.052 5.79 4.07 7
EMS controls with 3 strategies Proposed strategy
not existing (retrofit system)
15 1,243.00 $1,354.83 $— $197.98 $150.00 $0.052 6.31 5.16 9
Page 60 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Automated Controls EMS controls with 4 strategies Proposed strategy not existing (retrofit system) 15 1,251.00 $1,363.55 $— $197.98 $175.00 $0.052 5.68 5.18 7
EMS controls with 5 strategies Proposed strategy not existing (retrofit system) 15 1,268.00 $1,382.08 $— $197.98 $200.00 $0.052 5.20 5.24 9
EMS controls with 2 strategies Proposed strategy not existing (new system)
15 454.00 $494.84 $— $162.49 $70.00 $0.052 5.29 2.66 7
EMS controls with 3 strategies Proposed strategy not existing (new system) 15 496.00 $540.62 $— $162.49 $80.00 $0.052 5.11 2.87 9
EMS controls with 4 strategies Proposed strategy not existing (new system) 15 498.95 $543.84 $— $162.49 $90.00 $0.052 4.69 2.89 7

EMS controls with 5
strategies
Proposed strategy
not existing (new system)
15 511.75 $557.79 $— $162.49 $100.00 $0.052 4.41 2.95 9
Lodging room occupancy controls Manual controls 11 430.00 $305.61 $— $150.61 $75.00 $0.052 3.14 1.77 7
Low U-value, U-factor of .30 or less Standard windows

25 5.89 $8.37 $— $5.92 $2.50 $0.052 2.98 1.34 7
Adding reflective roof treatment Non-reflective low pitch roof 15 0.12 $0.13 $— $0.05 $0.05 $0.052 2.26 2.26 7
Increase to R11 min. insulation Insulation level, R2.5 or less 25 0.41 $0.59 $— $0.66 $0.40 $0.052 1.39 0.86 7, 10
Increase to R19 min. insulation Insulation level, R2.5 or less 25 0.47 $0.66 $— $0.66 $0.55 $0.052 1.15 0.97 7, 10
PC network power management No central control software in place 4 135.00 $28.75 $— $12.00 $10.00 $0.052 1.69 1.51 7
High efficiency washer Standard washer, electric HW 10 756.00 $411.96 $— $200.00 $125.00 $0.052 2.51 1.72 7
Energy free freeze resistant stock tank Thermostatically controlled electric
resistance element freeze protection
10 1,176.00 $919.86 $— $442.69 $100.00 $0.052 5.71 1.83 11
Demand-Side Management 2014 Annual Report Page 61
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Residential-type

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 13 154.14 $106.90 $— $67.90 $50.00 $0.052 1.84 1.41 12
-

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 13 68.17 $47.27 $— $29.74 $20.00 $0.052 2.01 1.42 13

2.0 gpm or less installed in health club/fitness business Showerhead using 2.2 gpm or greater 10 2,431.00 $1,324.70 $— $13.32 $15.00 $0.052 9.37 9.48 14

2.0 gpm or less installed in commercial business (non health club/fitness business)
Showerhead using 2.2 gpm or greater NComm_WtrHtr 10 129.00 $70.29 $— $13.32 $9.00 $0.052 4.48 3.51 1
Add refrigeration line insulation No insulation present 11 9.75 $5.98 $— $4.46 $2.00 $0.052 2.38 1.20 7
Install auto-closer - walk-in no/damaged auto-closer, low temp 8 2,547.00 $1,149.63 $— $139.32 $125.00 $0.052 4.47 4.23 7
Install auto-closer - reach-in Damaged auto-closer, low temp 8 560.00 $252.76 $— $139.32 $100.00 $0.052 1.96 1.50 7
Install auto-closer - walk-in No/damaged auto-closer, med. Temp 8 575.00 $259.54 $— $139.32 $100.00 $0.052 2.00 1.53 7
Install auto-closer - reach-in Damaged auto-closer, med. Temp 8 373.00 $168.36 $— $139.32 $70.00 $0.052 1.88 1.06 7
Add anti-sweat heat controls Low/med. temp case w/out controls
8 208.00 $93.88 $— $40.00 $40.00 $0.052 1.85 1.85 7
Add evaporative fan controls low or med. temp. walk-in or reach-in with no controls
15 408.00 $328.91 $— $161.74 $75.00 $0.052 3.42 1.80 7
Install ECM/PSC evap fan motor Med. or low temp. walk-in 15 593.00 $478.05 $— $296.78 $100.00 $0.052 3.65 1.46 7
Page 62 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Evaporative Fans Install ECM/PSC evap fan motor Med. or low temp. reach-in 15 318.00 $256.36 $— $84.45 $60.00 $0.052 3.35 2.54 7

Head pressure controller Standard head pressure control 16 440.00 $374.47 $— $272.60 $80.00 $0.052 3.64 1.27 7

Suction pressure controller Standard suction pressure control 16 104.00 $88.51 $— $86.91 $20.00 $0.052 3.48 0.96 7, 15
Non-cooled snack control Vending machine with no sensor 5 387.00 $107.66 $— $75.00 $50.00 $0.052 1.54 1.13 7

ENERGY STAR® undercounter (residential style) dishwasher
Standard dishwasher 12 2,210.00 $1,467.71 $251.95 $232.00 $200.00 $0.052 4.66 4.96 16

ENERGY STAR commercial dishwasher Standard commercial dishwasher
12 5,561.00 $3,693.19 $679.51 $3,978.00 $500.00 $0.052 4.68 1.02 16

ENERGY STAR listed electric combination oven (6-14 pans)
Standard electric oven 10 12,999.00 $7,577.91 $— $1,674.17 $1,100.00 $0.052 4.27 3.22 17

ENERGY STAR listed electric combination oven (15-20 pans)
Standard electric oven 10 17,877.00 $10,421.60 $— $457.41 $300.00 $0.052 8.48 7.51 17

ENERGY STAR listed electric convection oven Standard electric oven 10 1,672.00 $974.71 $— $946.42 $300.00 $0.052 2.52 0.94 15, 18

ENERGY STAR listed electric fryer Standard fryer 8 2,671.00 $1,253.86 $— $808.25 $400.00 $0.052 2.33 1.32 19

ENERGY STAR listed electric steamer - 3 pan Standard steamer 9 21,470.00 $11,313.49 $— $370.32 $80.00 $0.052 9.46 7.61 20

ENERGY STAR listed electric steamer - 4 pan Standard steamer 9 28,564.00 $15,051.64 $— $141.36 $100.00 $0.052 9.49 9.25 20

ENERGY STAR listed electric steamer - 5 pan Standard steamer 9 35,659.00 $18,790.31 $— $(276.91) $150.00 $0.052 9.38 11.91 20

ENERGY STAR listed electric steamer - 6 pan Standard steamer 9 42,754.00 $22,528.98 $— $61.30 $175.00 $0.052 9.39 9.86 20

ENERGY STAR listed electric steamer -10 pan or larger
Standard steamer 9 71,133.00 $37,483.13 $— $4,197.92 $200.00 $0.052 9.61 4.75 20
Demand-Side Management 2014 Annual Report Page 63
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Name Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
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
15 268.00 $248.78 $— $165.33 $60.00 $0.052 3.36 1.39 7
Variable speed drive on HVAC system applications: -supply -return -outside air -make-up air -hot water pumps
Single speed HVAC system fan/pump
15 996.00 $924.57 $— $142.05 $100.00 $0.052 6.09 4.77 7
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 Evergreen Consulting Group, LLC. Idaho Power Lighting Tool. 2014.
2 Measure not cost-effective. Measure to be monitored in 2015 to adjust weighted average. Measure included in the program to increase participation in a cost-effective program and to encourage adoption of higher efficiency equipment.
3 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009.
4 RTF. ComGroceryDisplayCaseLEDs_v2_2 and ComGroceryCaseLEDs_v1.1.xls. 2013. T12 to LED. Averaged the measures for less than 4 W/ln ft and 4-8.5 W/ln ft.
5 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.
6 Idaho Power Technical Reference Manual (TRM) prepared by ADM Associates, Inc. 2015. Weighted average of 6-25 ton units.
7 Idaho Power TRM prepared by ADM Associates, Inc. 2015.
8 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Averaged water cooled chillers.
9 Idaho Power TRM prepared by ADM Associates, Inc. 2015. Calculated from TRM spreadsheets.
10 Measure not cost-effective. Measure to remain in the program due to unquantifiable non-energy benefits.
11 RTF. AgStockWateringTank_v2_0.xlsm. 2013. Simple average of HZ 1, 2, & 3.
12 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.
14 RTF. ComDHWShowerhead_v3_0.xlsm. 2013.
15 Measure not cost-effective. Will monitor in 2015.
16 Idaho Power TRM prepared by ADM Associates, Inc. 2015. NEBs from water savings from RTF. ComDishwasher_v1_2.xlsm. 2012.
17 RTF. ComCookingCombinationOven_v2_0.xlsm. 2013. 18 RTF. ComCookingConvectionOven_v2_0.xlsm. Simple average of half and full size ovens. 2013.
19 RTF. ComCookingFryer_v2_0.xlsm. 2013.
20 RTF. ComCookingSteamer_v2_0.xlsm. 2013.

Page 64 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Irrigation Efficiency Rewards
Segment: Irrigation
2014 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ................................................................$276,286 Test Benefit Cost Ratio
Program Incentives 2,170,220 I Utility Cost Test $13,859,695 $ 2,446,507 5.67
Total Utility Cost ................................................................ $2,446,507 P Total Resource Cost Test 33,830,056 18,459,781 1.83
Ratepayer Impact Measure Test 13,859,695 9,955,636 1.39
Measure Equipment and Installation (Incremental Participant Cost) $18,183,495 M Participant Cost Test 29,649,711 18,183,495 1.63

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ................................= S * NTG
2014 Annual Gross Energy (kWh) ................................18,463,611 Total Resource Cost Test = (S + NUI + NEB) * NTG -I)*NTG)
NPV Cumulative Energy (kWh) ................................133,860,495 $12,599,723 Ratepayer Impact Measure Test = S * NTG
10% Credit (Northwest Power Act) ................................ 1,259,972 Participant Cost Test = B + I + NUI + NEB
Total Electric Savings ................................ $13,859,695 S
Assumptions for Levelized Calculations
Participant Bill Savings Discount Rate
NPV Cumulative Participant Savings ................................ $7,509,129 B Nominal (WACC) .....................................................................................6.77%
Real ((1 + WACC) / (1 + Escalation)) – 1 .................................................3.66%
Other Benefits Escalation Rate ...........................................................................................3.00%
Non-Utility Rebates/Incentives ................................ $— NUI Net-to-Gross (NTG) ....................................................................................100%
Non-Energy Benefits ................................................................ $19,970,361 NEB Minimum NTG Sensitivity ............................................................................18%
Average Customer Segment Rate/kWh .......................................................$0.059
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.
Green Rewind initiative is available to agricultural, commercial, and industrial customers. Agricultural motor rewinds are paid under Irrigation Efficiency.
Non-energy benefits, including yield, labor, and other benefits, reported by the customer.
Program cost-effectiveness modified in 2014 to reflect NTG of 100% for both Menu and Custom offering.
Demand-Side Management 2014 Annual Report Page 65
Supplement 1: Cost-Effectiveness Idaho Power Company

Year:2014 Program: Irrigation Efficiency Rewards Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
a Measure Descriptions Replacing
Measure Life (yrs)b
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Nozzle Replacement New flow-control-type nozzles replacing existing brass nozzles or worn out flow control nozzles of same flow rate or less.
Brass nozzles or worn out flow control nozzles of same flow rate or less
Unit IPC_Irrigation 4 40.60 $14.63 $— $6.66 $1.50 $0.015 6.94 2.01 1
New nozzles replacing
existing worn nozzles of same flow rate or less
Worn nozzle of
same flow rate or less
Unit IPC_Irrigation 4 40.60 $14.63 $— $2.49 $0.25 $0.015 17.03 4.72 1
Rebuilt or new brass impact sprinklers Unit IPC_Irrigation 5 28.26 $12.75 $— $14.49 $2.75 $0.015 4.02 0.85 1, 2
Rebuilt or new wheel line levelers Unit IPC_Irrigation 5 41.76 $18.84 $— $3.82 $0.75 $0.015 13.69 4.24 1
Center pivot/linear move: Install new sprinkler package on an existing system
Unit IPC_Irrigation 5 100.19 $45.19 $— $30.00 $8.00 $0.015 4.76 1.43 1
New gaskets for hand lines, wheel lines or portable mainline
Unit IPC_Irrigation 5 170.00 $76.68 $— $4.61 $1.00 $0.015 21.60 10.72 1
New drain hand lines, wheel lines, or portable mainline Unit IPC_Irrigation 5 176.25 $79.50 $— $16.06 $3.00 $0.015 14.09 4.25 1
New wheel line hubs Unit IPC_Irrigation 10 73.06 $63.19 $— $58.75 $12.00 $0.015 4.83 1.06 1
New goose neck with drop tube or boomback Outlet IPC_Irrigation 15 14.50 $17.61 $— $4.90 $1.00 $0.015 14.47 3.44 1
Cut and pipe press or weld repair of leaking hand lines, wheel lines, and portable mainline
Joint IPC_Irrigation 8 84.48 $59.65 $— $21.15 $8.00 $0.015 6.44 2.66 1
New center pivot base boot gasket Unit IPC_Irrigation 8 1,456.40 $1,028.39 $— $293.76 $125.00 $0.015 7.00 3.26 1
a Available measures in the Irrigation Efficiency Menu Incentive Option. For the Custom Incentive Option, projects are thoroughly reviewed by Idaho Power staff.
b Average measure life.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
g Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. AgIrrigationHardware_v3.xlsm. 2013. Three year weighted average of Western Idaho (13%), Eastern Washington & Oregon (4%), and Eastern & Southern Idaho (83%).
2 Measure not cost-effective. Measure to remain in the program due to unquantifiable non-energy benefits.

Page 66 Demand-Side Management 2014 Annual Report
Idaho Power Company Supplement 1: Cost-Effectiveness
Year:2014 Program: Irrigation Efficiency Rewards—Green Motors Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Green Motors Program Rewind Standard rewind practice IPC_Irrigation 18 317.00 $445.29 $— $157.66 $30.00 $0.050 9.71 2.57 1
Standard rewind practice IPC_Irrigation 18 425.00 $596.99 $— $175.90 $40.00 $0.050 9.75 3.03 1
Standard rewind practice IPC_Irrigation 17 595.00 $797.05 $— $200.98 $50.00 $0.050 9.99 3.45 1
Standard rewind practice IPC_Irrigation 17 640.00 $857.33 $— $220.74 $60.00 $0.050 9.32 3.39 1
Standard rewind practice IPC_Irrigation 17 746.00 $999.32 $— $269.75 $80.00 $0.050 8.52 3.25 1
Standard rewind practice IPC_Irrigation 17 802.00 $1,074.34 $— $298.62 $100.00 $0.050 7.67 3.17 1
Standard rewind practice IPC_Irrigation 20 765.00 $1,170.15 $— $352.19 $120.00 $0.050 7.39 3.00 1
Standard rewind practice IPC_Irrigation 20 788.00 $1,205.33 $— $380.68 $150.00 $0.050 6.36 2.87 1
Standard rewind practice IPC_Irrigation 20 1,040.00 $1,590.80 $— $472.24 $200.00 $0.050 6.31 3.03 1
Standard rewind practice IPC_Irrigation 20 1,157.00 $1,769.76 $— $530.37 $250.00 $0.050 5.75 3.01 1
Standard rewind practice IPC_Irrigation 20 1,376.00 $2,104.75 $— $590.78 $300.00 $0.050 5.71 3.19 1
Standard rewind practice IPC_Irrigation 20 1,821.00 $2,785.42 $— $711.22 $400.00 $0.050 5.67 3.47 1
Standard rewind practice IPC_Irrigation 20 2,823.00 $4,318.10 $— $914.10 $500.00 $0.050 6.73 4.09 1
Standard rewind practice IPC_Irrigation 20 3,370.00 $5,154.79 $— $923.98 $600.00 $0.050 6.71 4.72 1
Standard rewind practice IPC_Irrigation 20 3,929.00 $6,009.85 $— $968.43 $700.00 $0.050 6.70 5.16 1
Standard rewind practice IPC_Irrigation 20 4,456.00 $6,815.95 $— $1,081.64 $800.00 $0.050 6.66 5.23 1
Standard rewind practice IPC_Irrigation 20 5,003.00 $7,652.65 $— $1,182.32 $900.00 $0.050 6.65 5.34 1
Standard rewind practice IPC_Irrigation 20 5,567.00 $8,515.35 $— $1,277.31 $1,000.00 $0.050 6.66 5.47 1
Standard rewind practice IPC_Irrigation 20 6,193.00 $9,472.89 $— $1,882.27 $1,200.00 $0.050 6.27 4.32 1
Standard rewind practice IPC_Irrigation 20 7,195.00 $11,005.56 $— $2,053.56 $1,400.00 $0.050 6.25 4.56
Demand-Side Management 2014 Annual Report Page 67
Supplement 1: Cost-Effectiveness Idaho Power Company
Benefit Cost Benefit/Cost Tests
Measure Descriptions Replacing
Measure Life (yrs)a
Annual Gross Energy Savings (kWh/yr)b
NPV Avoided Costsc
Non-Energy Benefit (NEB)
Gross Incremental Participant Costd Incentive/ Unit Admin Cost ($/kWh)e UC Ratiof TRC Ratiog Source
Green Motors Program Rewind Standard rewind practice IPC_Irrigation 20 8,205.00 $12,550.47 $— $2,278.48 $1,600.00 $0.050 6.24 4.67
Standard rewind practice IPC_Irrigation 20 9,211.00 $14,089.26 $— $2,511.92 $1,800.00 $0.050 6.23 4.74
a Average measure life.
b Estimated kWh savings measured at the customers meter, excluding line losses.
c Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2013 Integrated Resource Plan (IRP). Includes 10 percent 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 2014 actuals.
f Utility Cost Ratio = (NPV Avoided Costs)/((Admin Cost/kWh * kWh Savings ) + Incentives).
g Total Resource Cost Ratio = (NPV Avoided Costs + NEB) / ((Admin Cost/kWh * kWh Savings) + Incentives + (Incremental Participant Cost - Incentives))
1 RTF. AgMotorsRewind_v2_0.xlsm. 2013.
Page 68 Demand-Side Management 2014 Annual Report