20130403DSM 2012 Annual Report Supplement 1.PDF

March 15, 2013
SUPPLEMENT 1:
Cost-Effectiveness
Demand-Side Management
2012 ANNUAL REPORT
Printed on recycled paper
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page i
TABLE OF CONTENTS
Table of Contents ......................................................................................................................................... i
List of Tables .............................................................................................................................................. ii
Supplement 1: Cost-Effectiveness ...............................................................................................................1
Cost-Effectiveness .................................................................................................................................1
Methodology ....................................................................................................................................1
Assumptions .....................................................................................................................................2
Net-to-Gross .....................................................................................................................................4
Results ..............................................................................................................................................4
2012 DSM Detailed Expense by Program .............................................................................................7
Cost-Effectiveness Tables by Program ......................................................................................................13
A/C Cool Credit .............................................................................................................................13
FlexPeak Management ...................................................................................................................15
Irrigation Peak Rewards .................................................................................................................17
Ductless Heat Pump Pilot ..............................................................................................................19
Energy Efficient Lighting ..............................................................................................................21
Energy House Calls........................................................................................................................23
ENERGY STAR® Homes Northwest ............................................................................................27
Heating & Cooling Efficiency Program ........................................................................................29
Home Improvement Program ........................................................................................................33
Home Products Program ................................................................................................................45
Rebate Advantage ..........................................................................................................................49
See ya later, refrigerator® ...............................................................................................................53
Weatherization Assistance for Qualified Customers .....................................................................55
Weatherization Solutions for Eligible Customers..........................................................................57
Building Efficiency ........................................................................................................................59
Custom Efficiency .........................................................................................................................63
Easy Upgrades ...............................................................................................................................67
Irrigation Efficiency .......................................................................................................................79

Supplement 1: Cost-Effectiveness Idaho Power Company
Page ii Demand-Side Management 2012 Annual Report
LIST OF TABLES
Table 1. 2012 non-cost-effective measures ........................................................................................6
Table 2. 2012 DSM detailed expenses by program (dollars) .............................................................7
Table 3. Cost-effectiveness summary by program...........................................................................11

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 1
SUPPLEMENT 1: COST-EFFECTIVENESS
Cost-Effectiveness
Idaho Power considers cost-effectiveness of primary importance in the design, implementation,
and tracking of energy efficiency and demand response programs. The majority of Idaho Power’s energy
efficiency and demand response programs are identified through the Integrated Resource Plan (IRP)
process. Because of Idaho Power’s diversified portfolio of programs covering all customer classes, in the 2011 IRP, most of the new potential for energy efficiency is based on the addition of new measures, new technologies, or existing program growth rather than complete new programs. The IRP
process remains the same for the determination of measures to be adopted for program inclusion.
Specific cost-effective programs or energy-saving measures are screened by sector to determine if the
levelized cost of these programs or measures is less than supply-side resource alternatives. If they are shown to be less costly than supply-side resources from a levelized cost perspective, the hourly shaped energy savings is subsequently included in the IRP as a resource.
Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power
performs a cost-effectiveness analysis to assess whether a specific potential program design will be
cost-effective from the perspective of Idaho Power and its customers. Incorporated into these models are inputs from various sources to use the most current and reliable information available. When possible, Idaho Power leverages the experiences of other utilities in the region, or throughout the country,
to identify specific program parameters. This is typically accomplished through discussions with other
utilities’ program managers and researchers. Idaho Power also uses electric industry research
organizations, such as E Source, Edison Electrical Institute (EEI), Consortium for Energy Efficiency (CEE), American Council for an Energy Efficient Economy (ACEEE), Advanced Load Control Alliance (ALCA), Association of Energy Service Professionals (AESP), and others to identify similar programs
and their results. Additionally, Idaho Power relies on the results of program impact evaluations and
recommendations from consultants. In 2012, Idaho Power contracted with ADM Associates, Inc.,
Portland Energy Conservation, Inc. (PECI), University of Idaho, D&R International Ltd., EnerNOC Utility Solutions™ Consulting Group, and The Cadmus Group for program evaluations and research.
Idaho Power’s goal is to have all programs reach benefit/cost (B/C) ratios of 1.0 or greater for the total
resource cost (TRC) test, utility cost (UC) test, and participant cost test (PCT) at the program level and
the measure level where appropriate. An exception to the measure level cost-effectiveness is when there
is an interaction between measures. Idaho Power may launch a pilot or a program to evaluate estimates or assumptions in the cost-effectiveness analysis. Following implementation of a program, cost-effectiveness analyses are reviewed as new inputs from actual program activity become available,
such as actual program expenses, savings, or participation levels. If measures or programs are
determined to be not cost-effective after implementation, the program or measures are re-examined,
including input provided from the company’s Energy Efficiency Advisory Group (EEAG).
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 National Action Plan on Demand Response. Traditionally, Idaho Power
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 2 Demand-Side Management 2012 Annual Report
has primarily used the TRC test and the UC test to develop B/C ratios to determine the
cost-effectiveness of demand-side management (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 2012 dollars. The result of the one-year perspective is shown in Supplement
1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2012 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. As such, demand response programs are analyzed over the program life where
historical program demand reduction and expenses are combined with forecasted program activity to
better compare the program to a supply-side resource. While cost-effectiveness is determined over the
program life, it is also calculated for each individual year.
Because the 2013 IRP process has indicated a lack of near-term capacity deficits, on December 21,
2012, Idaho Power filed a proposal with the Idaho Public Utilities Commission (IPUC) to temporarily
suspend two of its demand response programs, A/C Cool Credit and Irrigation Peak Rewards, for 2013.
A settlement workshop was held in February 2013 with Idaho Power and interested stakeholders to
discuss plans for the 2013 cycling season. The stipulation was filed on February 14, 2013. FlexPeak Management was not included in the original filing due to the company’s contractual
obligation to EnerNOC Inc.; however, Idaho Power intends to meet with all stakeholders in workshops
to further discuss future changes and identify the best, long-term solutions for 2014 and beyond. Due to
the uncertainty of these programs and the fact that an order on Case No. IPC-E-12-29 is pending,
Idaho Power used the assumptions from the information known prior to the filing.
Assumptions
Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumption for various measures. These assumptions are routinely reviewed and updated as new information
becomes available. For many of the measures within Demand-Side Management 2012 Annual Report
Supplement 1: Cost-Effectiveness, savings, costs, and load shapes were derived from either the Regional
Technical Forum (RTF) or the Demand-Side Management Potential Study conducted by Nexant, Inc., in 2009. An additional resource for cost-effectiveness data includes the Idaho Power Energy Efficiency Potential Study conducted by EnerNOC Utility Solutions Consulting Group in 2012. The RTF, which
meets monthly, 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, in turn, applies those assumptions 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
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 3
2006 dollars, measures with costs from the RTF have been escalated by 15.77 percent in 2012. This
percentage is provided by the RTF.
Idaho Power also relies on other sources, such as the Northwest Power and Conservation Council
(NPCC), 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. On occasion, Idaho Power will also use internal engineering
estimates and calculations for savings and costs based on information gathered from previous projects.
The remaining inputs used in the cost-effectiveness models are obtained from the IRP process.
The Technical Appendix of Idaho Power’s 2011 IRP is the source for the financial assumptions until the 2013 IRP is acknowledged, including the discount rate and escalation rate. As recommended by the
NAPEE Understanding Cost-Effectiveness of Energy Efficiency Programs¸ Idaho Power’s weighted
average cost of capital (WACC) of 7 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 made
difficult by 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 2012 average customer segment rate and is not
escalated, the participant bill savings is discounted using a real discount rate of 3.88 percent, which is
based on the 2011 IRP’s WACC of 7 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
The IRP is also the source of the DSM alternative costs, which is the value of energy savings and
demand reduction resulting from the DSM programs. These DSM alternative costs vary by season and time of day and are applied to an end-use load shape to obtain the value of that particular measure or program. The DSM alternative energy costs are based on both the projected fuel costs of a peaking unit
and forward electricity prices as determined by Idaho Power’s power supply model, AURORAxmp®
Electric Market Model. The avoided capital cost of capacity is based on a gas-fired, simple-cycle
turbine. In the 2011 IRP, the annual avoided capacity cost is $94/kW. When multiplied by the Effective Load Carrying Capacity (ELCC) of 93.4 percent, the annual avoided capacity cost is $87.80/kW. The ELCC reduces the avoided capacity cost benefit.
Because demand response programs do not match the availability of generation resources,
these programs should not claim the full avoided capacity cost benefit of that supply-side resource.
In 2011, Idaho Power determined the ELCC for demand response programs by creating load duration curves using five years of actual total system load data and used the top 100 hours (adjusted for demand response activity) of each year. Of those top 500 hours, the number of hours that fell within the
operating parameters of one or more demand response program between June 1 and August 31 was used
to calculate the ELCC. Approximately 6.6 percent of the total hours were outside the programs’
parameters. Therefore, an ELCC of 93.4 percent is now applied to the avoided capacity cost of a simple-cycle gas turbine in the cost-effectiveness calculation of demand response programs.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 4 Demand-Side Management 2012 Annual Report
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:
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.
For most programs and individual measures, the NTG ratios are derived from the Demand-Side
Management Potential Study or the California Public Utilities Commission (CPUC) DEER. The NTG
ratio adjustment is shown as part of Supplement 1: Cost-Effectiveness for each program and measure.
However, for some programs, such as A/C Cool Credit, Energy Efficient Lighting, Irrigation Efficiency, and See ya later, refrigerator®, the unit incremental savings are net realized energy savings from third-party sources that take into account an NTG ratio adjustment. While each project within the
Custom Efficiency program is analyzed independently, and Idaho Power believes there is considerable
spillover from this program; a NTG ratio adjustment of 69 percent, the standard custom program NTG
ratio from DEER1, which includes a spillover adjustment, is used to calculate the cost-effectiveness of this program.
After reviewing the company’s TRC test calculation, Idaho Power determined it should also apply the
NTG ratio to the non-energy benefits. The company has adjusted its TRC formula for both the program
and measure cost-effectiveness tables. The formula change has resulted in a slight decrease in
cost-effectiveness for programs or measures that use a NTG ratio in the TRC calculation.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis. As part of the 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 the demand response programs, Weatherization Assistance for Qualified Customers (WAQC), Weatherization Solutions for Eligible
Customers, See ya later, refrigerator®, and Energy House Calls. These programs have few or no
customer costs. The Irrigation Peak Rewards program does have some direct costs for participants with
small horsepower (hp) pumps, where a fee is charged to install program equipment at the enrolled
service location. In addition to this fee, Idaho Power also calculated the additional labor expense an

1 Source: CPUC DEER NTFR Update Process for 2006–2007 Programs, found at http://www.deeresources.com/deer2008exante/downloads/DEER%200607%20Measure%20Update%20Report.pdf
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 5
irrigator may incur for resetting each pump after an event as a cost for the participant. For energy
efficiency programs, the cost-effectiveness models do not assume any ongoing participant costs.
The Demand-Side Management 2012 Annual Report contains program UC and TRC B/C ratios using
actual cost information over the life of the program through 2012. Supplement 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using actual information from 2012,
includes results of the PCT, and includes 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 2012, all but two of Idaho Power’s energy efficiency programs were cost-effective from the UC,
TRC, and PCT perspective. WAQC had a TRC of 0.71 and Weatherization Solutions for Eligible
Customers had a TRC of 0.47, due to the lower estimated savings per home that resulted from the
impact evaluation conducted by D&R International. Idaho Power has adopted the following commission 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 2.71percent was calculated from the $1,335,509 of indirect program expenses divided by the total DSM expenses
of $49,326,859 as shown in Appendix 3 of the Demand-Side Management 2012 Annual Report.
• Applied the 10 percent conservation preference adder.
• Claimed one dollar of non-energy benefits for each dollar of utility and federal funds invested in heath, safety, and repair measures.
All of the demand response programs were determined to be cost-effective from the long-term
perspective. Since this report is focused on cost-effectiveness for 2012 and with no final order pending
on IPC-E-12-29, Idaho Power did not change the forecast for future expenses and program performance of its demand response programs to reflect the filing. As a result, Idaho Power has used the program
operation assumptions that were in place in fall 2012 at the time of budgeting for 2013. Under these
assumptions, the B/C ratios for A/C Cool Credit and Irrigation Peak Rewards are calculated over a
20-year program life while the B/C ratios for FlexPeak Management are calculated over a 10-year life.
This is done to be useful in the IRP planning process and to account for the fact that demand response programs’ costs and benefits are inherently different from energy efficiency programs. For this report
the cost-effectiveness models were updated to include 2012 expenses and program performance results
and 2013 budgeted expenses and expected results.
Idaho Power also calculates cost-effectiveness for each demand response program on a year-to-year
basis. The A/C Cool Credit program was determined to not be cost-effective for 2012 with a TRC of 0.68. However, under the original program assumptions with full participation in 2013 and a realized
demand reduction of 1.09 kW per participant, the program has the potential to be cost-effective for 2013
despite the additional costs to change the paging switches to AMI compatible switches. For 2012,
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 6 Demand-Side Management 2012 Annual Report
FlexPeak Management and Irrigation Peak Rewards programs passed the B/C tests with TRCs of 1.21
and 2.40 respectively. The program life TRC ratios for A/C Cool Credit, Irrigation Peak Reward, and
FlexPeak Management programs are 1.33, 1.72, and 1.22, respectively.
Fifty-two measures within programs were not cost-effective from the UC or TRC perspective. Of those 52 measures, 40 were measures were removed from the program offerings in 2012. Eleven measures
will be reviewed and possibly modified in 2013. One measure will be removed in 2013.
Table 1. 2012 non-cost-effective measures
Program
Number of
Measures Notes
Easy Upgrades 4 These measures will be reviewed in 2013.
ENERGY STAR® Homes Northwest 4 Three measures were removed from the program in 2012. One measure will be reviewed in 2013.
Heating & Cooling Efficiency Program 2 These measures will be reviewed in 2013.
Home Improvement Program 34 The program was redesigned in 2012. Fifteen measures are for varying insulation levels for non-electrically heated homes that
were paid in the program and no longer qualified after March 31, 2012. Nineteen measures are for varying insulation levels for electrically heated homes paid in the program and no longer
qualified after March 31 under the redesigned program in which the existing insulation must be R20 or less.
Home Products Program 6 Three lighting measures were removed in 2012. One clothes washer measure will be removed in 2013. The two refrigerator measures were not cost-effective due to the higher administrative
costs, which are calculated on a dollar-per-kWh-saved basis. This number was impacted by lower program savings attributed to the clothes washer measure saving adjustment. The measures
will be monitored in 2013.
Irrigation Efficiency Rewards 2 One measure was revised in 2012 to remove the high-cost item that brought down cost-effectiveness. One measure will be
reviewed in 2013.
Total 52

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 the 2012 impact evaluation, measure-level realized energy saving data is not available. The measure level cost-effectiveness analysis is not included in this report, due to the lack of realized data at the measure level. This is a change in reporting from the 2011 Supplement 1:
Cost-Effectiveness report.
The measure-level cost-effectiveness includes inputs of measure life, energy savings, incremental cost,
NTG factors, incentives, program administration cost, and net benefit. Program administration costs include all non-incentive costs: labor, marketing, training, education, purchased services, and evaluation. This year on the measure-level cost-effectiveness tables, the column containing the demand reduction
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 7
from measures has been removed. This information is not readily available nor currently used in the
measure-level cost-effectiveness analysis.
2012 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 2012 Annual Report. These expenses are broken out by major-expense type
(incentives, labor/administration, materials, other expenses, and purchased services).
Table 2. 2012 DSM detailed expenses by program (dollars)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Energy Efficiency/Demand Response
Residential
A/C Cool Credit a .............................................................................. $ 4,804,566 $ 92,810 $ 830,618 $ 5,727,994
Customer Incentives ...................................................................... (81,080) 10,006 830,618 759,544
Labor/Administrative Expense ....................................................... 109,611 5,762 0 115,373
Materials & Equipment .................................................................. 3,298,847 145 0 3,298,992
Other Expense .............................................................................. 47,530 2,767 0 12,711
Purchased Services ...................................................................... 1,429,657 74,130 0 1,541,374
Ductless Heat Pump Pilot................................................................ 153,017 6,850 0 159,867
Customer Incentives ...................................................................... 91,750 3,750 0 95,500
Labor/Administrative Expense ....................................................... 37,697 1,983 0 39,680
Other Expense .............................................................................. 19,184 886 0 20,070
Purchased Services ...................................................................... 4,386 231 0 4,617
Energy Efficient Lighting................................................................. 1,110,329 16,507 0 1,126,836
Customer Incentives ...................................................................... 755,838 9,907 0 765,745
Labor/Administrative Expense ....................................................... 55,009 2,900 0 57,909
Other Expense .............................................................................. 3,903 194 0 4,097
Purchased Services ...................................................................... 295,580 3,506 0 299,086
Energy House Calls ......................................................................... 272,666 3,217 0 275,884
Labor/Administrative Expense ....................................................... 41,157 2,165 0 43,322
Materials & Equipment .................................................................. 326 11 0 337
Other Expense .............................................................................. 4,330 151 0 4,480
Purchased Services ...................................................................... 226,854 890 0 227,744
ENERGY STAR® Homes .................................................................. 450,727 2,458 0 453,186
Customer Incentives ...................................................................... 404,000 0 0 404,000
Labor/Administrative Expense ....................................................... 32,214 1,694 0 33,908
Other Expense .............................................................................. 14,514 764 0 15,278
Heating & Cooling Efficiency Program ........................................... 175,483 6,798 0 182,281
Customer Incentives ...................................................................... 56,650 1,550 0 58,200
Labor/Administrative Expense ....................................................... 54,478 2,867 0 57,345
Materials & Equipment .................................................................. 5,089 307 0 5,397
Other Expense .............................................................................. 6,315 (404) 0 5,910
Purchased Services ...................................................................... 52,951 2,479 0 55,430
Home Improvement Program .......................................................... 385,091 0 0 385,091
Customer Incentives ...................................................................... 202,004 0 0 202,004
Labor/Administrative Expense ....................................................... 93,337 0 0 93,337
Other Expense .............................................................................. 25,680 0 0 25,680
Purchased Services ...................................................................... 64,070 0 0 64,070

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 8 Demand-Side Management 2012 Annual Report
Table 2. 2012 DSM Detailed Expenses by Program (Continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Home Products Program ........................................................ $ 640,098 $ 18,829 $ 105 $ 659,032
Customer Incentives ............................................................. 491,143 11,076 105 502,324
Labor/Administrative Expense .............................................. 77,922 4,101 0 82,023
Materials & Equipment ......................................................... 421 22 0 443
Other Expense ..................................................................... 7,327 346 0 7,673
Purchased Services ............................................................. 63,285 3,284 0 66,569
Oregon Residential Weatherization ....................................... 0 4,051 465 4,516
Customer Incentives ............................................................. 0 1,722 0 1,722
Labor/Administrative Expense .............................................. 0 2,328 465 2,793
Rebate Advantage .................................................................. 34,926 2,316 0 37,241
Customer Incentives ............................................................. 12,000 1,000 0 13,000
Labor/Administrative Expense .............................................. 14,622 769 0 15,391
Other Expense ..................................................................... 5,065 345 0 5,410
Purchased Services ............................................................. 3,238 201 0 3,440
See ya later, refrigerator® ....................................................... 596,167 16,979 0 613,146
Customer Incentives ............................................................. 98,910 1,830 0 100,740
Labor/Administrative Expense .............................................. 46,924 2,456 0 49,380
Other Expense ..................................................................... 81,377 4,262 0 85,639
Purchased Services ............................................................. 368,956 8,431 0 377,388
Weatherization Assistance for Qualified Customers ............ 0 0 1,370,141 1,370,141
Labor/Administrative Expense .............................................. 0 0 52,501 52,501
Other Expense ..................................................................... 0 0 28,114 28,114
Purchased Services ............................................................. 0 0 1,289,525 1,289,525
Weatherization Solutions for Eligible Customersa ............... 1,048,461 0 22,094 1,070,556
Labor/Administrative Expense .............................................. 10,033 0 22,094 32,127
Other Expense ..................................................................... 17,286 0 0 17,286
Purchased Services ............................................................. 1,021,142 0 0 1,021,142
Residential Total ......................................................................... $ 9,671,531 $ 170,816 $ 2,223,423 $ 12,065,769
Commercial/Industrial
Building Efficiency ................................................................. 1,579,121 13,451 0 1,592,572
Customer Incentives ............................................................. 1,322,045 0 0 1,322,045
Labor/Administrative Expense .............................................. 127,472 6,710 0 134,182
Other Expense ..................................................................... 14,845 701 0 15,546
Purchased Services ............................................................. 114,759 6,040 0 120,799
Comprehensive Lighting ........................................................ 64,094 0 0 64,094
Customer Incentives ............................................................. 63,683 0 0 63,683
Labor/Administrative Expense .............................................. 411 0 0 411
Easy Upgrades ........................................................................ 5,150,422 199,331 0 5,349,753
Customer Incentives ............................................................. 4,267,443 152,862 0 4,420,305
Labor/Administrative Expense .............................................. 365,083 19,212 0 384,295
Materials & Equipment ......................................................... 55 3 0 58
Other Expense ..................................................................... 45,050 2,371 0 47,421
Purchased Services ............................................................. 472,790 24,884 0 497,674

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 9
Table 2. 2012 DSM Detailed Expenses by Program (Continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
FlexPeak Management a ................................................................... $ 98,973 $ 150,489 $ 2,760,360 $ 3,009,822
Customer Incentives ...................................................................... 0 145,282 2,760,360 2,905,642
Labor/Administrative Expense ....................................................... 93,598 4,924 0 98,521
Other Expense .............................................................................. 0 0 0 0
Purchased Services ...................................................................... 5,375 283 0 5,658
Oregon Commercial Audits ............................................................. 0 12,470 0 12,470
Labor/Administrative Expense ....................................................... 0 6,777 0 6,777
Other Expense .............................................................................. 0 1,193 0 1,193
Purchased Services ...................................................................... 0 4,500 0 4,500
Custom Efficiency b .......................................................................... 923,050 115,866 6,053,665 7,092,581
Customer Incentives ...................................................................... 0 126,211 6,053,255 6,179,466
Labor/Administrative Expense ....................................................... 459,550 24,176 297 484,024
Other Expense .............................................................................. 199,055 10,411 0 209,466
Purchased Services ...................................................................... 264,445 (44,931) 113 219,626
Commercial Total ................................................................................ $ 7,815,659 $ 491,607 $ 8,814,025 $ 17,121,292
Irrigation
Irrigation Efficiency Rewards ......................................................... 1,978,729 360,689 33,782 2,373,201
Customer Incentives ...................................................................... 1,697,704 346,125 0 2,043,829
Labor/Administrative Expense ....................................................... 234,159 12,325 33,782 280,266
Materials & Equipment .................................................................. 1,088 57 0 1,146
Other Expense .............................................................................. 19,167 1,009 0 20,176
Purchased Services ...................................................................... 26,611 1,174 0 27,784
Irrigation Peak Rewards a ................................................................ 1,309,107 95,863 11,018,394 12,423,364
Customer Incentives ...................................................................... (13,500) 53,368 10,971,325 11,011,193
Labor/Administrative Expense ....................................................... 51,751 2,726 47,069 101,546
Materials & Equipment .................................................................. 1,002 53 0 1,055
Other Expense .............................................................................. 4,111 216 0 4,327
Purchased Services ...................................................................... 1,265,744 39,499 0 1,305,244
Irrigation Total ..................................................................................... $ 3,287,837 $ 456,552 $ 11,052,175 $ 14,796,565
Energy Efficiency Total ....................................................................... $ 20,775,027 $ 1,118,975 $ 22,089,624 $ 43,983,625
Market Transformation
NEEA c .............................................................................................. 3,210,768 168,988 0 3,379,756
Purchased Services ...................................................................... 3,210,768 168,988 0 3,379,756
Market Transformation Total .............................................................. $ 3,210,768 $ 168,988 $ 0 $ 3,379,756
Other Programs and Activities
Residential
Residential Energy Efficiency Education Initiative ....................... 165,919 8,819 0 174,738
Labor/Administrative Expense ....................................................... 118,597 6,242 0 124,840
Materials & Equipment .................................................................. 837 44 0 881
Other Expense .............................................................................. 46,485 2,533 0 49,018
Residential Economizer d ................................................................ 93,593 (101) 0 93,491
Labor/Administrative Expense ....................................................... 38,141 0 0 38,141
Materials & Equipment .................................................................. 708 (101) 0 607
Other Expense .............................................................................. 3,653 0 0 3,653
Purchased Services ...................................................................... 51,091 0 0 51,091
Residential Total .................................................................................. $ 259,511 $ 8,718 $ 0 $ 268,229

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 10 Demand-Side Management 2012 Annual Report
Table 2. 2012 DSM Detailed Expenses by Program (Continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Commercial
Commercial Education Initiative ..................................................... $ 70,099 $ 3,689 $ 0 $ 73,788
Labor/Administrative Expense ....................................................... 60,159 3,165 0 63,324
Other Expense .............................................................................. 8,091 426 0 8,517
Purchased Services ...................................................................... 1,850 97 0 1,947
Commercial Total ................................................................................ $ 70,099 $ 3,689 $ 0 $ 73,788
Other
Energy Efficiency Direct Program Overhead ................................. 271,622 14,329 0 285,951
Labor/Administrative Expense ....................................................... 184,370 9,824 0 194,194
Other Expense .............................................................................. 83,116 4,287 0 87,404
Purchased Services ...................................................................... 4,136 218 0 4,354
Local Energy Efficiency Funds ....................................................... 0 0 0 0
Other Expense .............................................................................. 0 0 0 0
Other Total ........................................................................................... $ 271,622 $ 14,329 $ 0 $ 285,951
Other Programs and Activities Total .................................................. $ 601,233 $ 26,736 $ 0 $ 627,968
Indirect Program Expenses
Residential Energy Efficiency Overhead ...................................... 172,819 9,051 0 181,869
Labor/Administrative Expense ....................................................... 151,232 7,860 0 159,092
Other Expense .............................................................................. 0 0 0 0
Purchased Services ...................................................................... 21,586 1,190 0 22,777
Commercial/Industrial Energy Efficiency Overhead ..................... 171,673 9,096 7,784 188,554
Labor/Administrative Expense ....................................................... 153,435 8,084 20 161,539
Materials & Equipment .................................................................. (258) (15) 0 (273)
Purchased Services ...................................................................... 18,495 1,028 7,765 27,288
Energy Efficiency Accounting and Analysis ................................. 898,944 47,050 142,241 1,088,236
Labor/Administrative Expense ....................................................... 415,646 21,879 136,291 573,816
Other Expense .............................................................................. 0 0 5,950 5,950
Purchased Services ...................................................................... 483,299 25,171 0 508,469
Energy Efficiency Advisory Group ................................................. 2,710 142 0 2,852
Labor/Administrative Expense ....................................................... 2,507 132 0 2,639
Other Expense .............................................................................. 203 11 0 214
Special Accounting Entries e........................................................... (93,985) 2,291 (34,308) (125,993)
Indirect Program Expenses Total ....................................................... $ 1,152,161 $ 67,631 $ 115,718 $ 1,335,518
Totals.................................................................................................... $ 25,739,197 $ 1,382,330 $ 22,205,341 $ 49,326,859
a Per order 32426, the Idaho Public Utilities Commission (IPUC) determined Idaho Power may recover 100% of its Idaho demand response incentives through the
Power Cost Adjustment (PCA) mechanism. b Idaho Custom Efficiency incentives, Idaho Power balance of $6,053,665, was not included in base rates for 2012.
c NEEA funding addressed in IPUC per Order No. 31080, dated May 12, 2010. 2013 annual expense expected at $3.8 million (see footnote, Appendix 1 for additional information)
d Residential Economizer 2011 Oregon Rider balance of $101 was reclassified to Idaho Rider in 2012.
e Special Accounting Entries, Idaho Power accrual amount of ($34,146), was not included in base rates for 2012.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 11
Table 3. Cost-effectiveness summary by program
2012 Benefit/Cost Tests
Program
Utility Cost
(UC)
Total Resource
Cost (TRC)
Ratepayer Impact
Measure (RIM)
Participant
Cost (PCT)
A/C Cool Credit .......................................................... 1.33 1.33 1.36 N/A
FlexPeak Management ............................................... 1.22 1.22 1.22 N/A
Irrigation Peak Rewards ............................................. 1.79 1.72 1.97 N/A
Ductless Heat Pump Pilot ........................................... 3.76 1.14 1.09 1.06
Energy Efficient Lighting ............................................. 5.60 2.62 0.89 3.30
Energy House Calls .................................................... 4.08 4.08 0.90 N/A
ENERGY STAR® Homes Northwest ........................... 1.73 1.05 0.75 1.49
Heating & Cooling Efficiency Program ........................ 5.11 1.61 1.18 1.48
Home Improvement Program ...................................... 2.39 1.27 0.92 1.55
Home Products Program ............................................ 1.18 1.06 0.61 2.05
Rebate Advantage ...................................................... 6.13 3.51 1.00 5.26
See ya later, refrigerator® ........................................... 1.60 1.60 0.67 N/A
Weatherization Assistance for Qualified Customers .... 0.84 0.71 0.53 N/A
Weatherization Solutions for Eligible Customers ......... 0.43 0.47 0.33 N/A
Building Efficiency ...................................................... 9.08 2.10 1.53 1.40
Custom Efficiency ....................................................... 4.66 2.97 1.86 1.79
Easy Upgrades ........................................................... 5.43 3.47 1.38 2.94
Irrigation Efficiency ..................................................... 3.98 1.64 1.49 1.31

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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 13
COST-EFFECTIVENESS TABLES BY PROGRAM
A/C Cool Credit
Segment: Residential
20-Year Program Cost-Effectiveness Summary
Program Inception: 2003
Cost Inputs (net-present value [NPV]) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................. $ 24,889,755 Test Benefit Cost Ratio
Total Program Incentives .................................................... 9,632,508 I Utility Cost Test ................................... $ 47,065,293 $ 35,498,784 1.33
Total Utility Cost ................................................................. $ 34,522,264 P Total Resource Cost Test ................... 47,065,293 35,498,784 1.33
Ratepayer Impact Measure Test ......... 47,065,293 34,522,264 1.36
Total Shifted Energy Utility Cost ........................................... $ 976,520 SE Participant Cost Test ........................... N/A N/A N/A

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

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S = P + SE
Cumulative Energy (kWh) ............................. 22,302,196 $ 2,225,381 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2022 Reduction Capacity (MW)..................... 49 44,839,913 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings .................................... $ 47,065,293 S Participant Cost Test ................................ N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ — B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response .................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: No final order on Case No. IPC-E-12-29. Model includes program operation assumptions prior to November 30, 2012. Updated to include 2012 expenses and program performance results and 2013 budgeted expenses and expected results.
2022 Reduction capacity based on the assumption of 40,000 participants at an average realized load reduction of 1.09 kW (1.23 kW with Summer Peak Line Loss of 13%).

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Page 14 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 15
FlexPeak Management
Segment: Commercial/Industrial
10-Year Program Cost-Effectiveness Summary
Program Inception: 2009
Cost Inputs (net-present value [NPV]) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................. $ 985,271 Test Benefit Cost Ratio
Total Program Incentives .................................................... 24,562,377 I Utility Cost Test ................................... $ 31,151,571 $ 25,610,645 1.22
Total Utility Cost ................................................................. $ 25,547,648 P Total Resource Cost Test ................... 31,151,571 $ 25,610,645 1.22
Ratepayer Impact Measure Test ......... 31,151,571 $ 25,547,648 1.22
Total Shifted Energy Utility Cost ........................................... $ 62,997 SE Participant Cost Test ........................... N/A N/A N/A

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

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S = P + SE
Cumulative Energy (kWh) ............................. 17,007,679 $ 1,539,680 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2018 Reduction Capacity (MW)..................... 45 29,611,891 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings .................................... $ 31,151,571 S Participant Cost Test ................................ N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ — B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response .................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: No final order on Case No. IPC-E-12-29. Model includes program operation assumptions prior to November 30, 2012. Updated to include 2012 expenses and program performance results and 2013 budgeted expenses and expected results.
2018 Reduction capacity based on expected target to achieve 40 MW (45 MW with Summer Peak Line Loss of 13%).

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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 17
Irrigation Peak Rewards
Segment: Irrigation
20-Year Program Cost-Effectiveness Summary
Program Inception: 2009
Cost Inputs (net-present value [NPV]) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................. $ 17,475,325 Test Benefit Cost Ratio
Total Program Incentives .................................................... 178,328,069 I Utility Cost Test ................................... $ 385,325,272 $ 214,690,560 1.79
Total Utility Cost ................................................................. $ 195,803,394 P Total Resource Cost Test ................... 385,325,272 224,502,738 1.72
Ratepayer Impact Measure Test ......... 385,325,272 195,803,394 1.97
Total Shifted Energy Utility Cost ........................................... $ 18,887,167 SE Participant Cost Test ........................... N/A N/A N/A

Total Measure Equipment and Installation (Incremental Participant Cost) .............................................. $ 9,812,178 M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S = P + SE
Cumulative Energy (kWh) ............................. 180,158,230 $ 22,308,607 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2028 Reduction Capacity (MW)..................... 327 363,016,665 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings .................................... $ 385,325,272 S Participant Cost Test ................................ N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ — B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response .................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: No final order on Case No. IPC-E-12-29. Model includes program operation assumptions prior to November 30, 2012. Updated to include 2012 expenses and program performance results and 2013 budgeted expenses and expected results.
Because of the fixed and variable incentive structure, the nature of summer peak loads, and the weather in 2012, the program was not dispatched in 2012.
2028 Reduction capacity based on the assumption that the available capacity will increase slightly in 2013 over 2012 and remain constant until 2028.

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Page 18 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 19
Ductless Heat Pump Pilot
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 64,367 Test Benefit Cost Ratio
Program Incentives ............................................................. 95,500 I Utility Cost Test ................................... $ 601,201 $ 159,867 3.76
Total Utility Cost ................................................................. $ 159,867 P Total Resource Cost Test ................... 601,201 526,239 1.14
Ratepayer Impact Measure Test ......... 601,201 551,845 1.09
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 553,466 M Participant Cost Test ........................... 585,473 553,466 1.06

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 444,500 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 5,779,575 $ 751,502 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 751,502 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 489,973 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 20 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Ductless Heat Pump Pilot Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Ductless Heat Pump High-efficiency ductless split heat pump system—existing single family w/ zonal electric heat
Zonal electric Unit Heating and cooling
20 80% 3,500.00 $5,541.01 $— $4,358.00 $750.00 $0.145 3.53 1.07 1
Ductless Heat Pump High-efficiency ductless split heat pump system—
existing single family w/ electric FAC w/ or w/o CAC
Electric forced air furnace w/
or w/o central A/C
Unit Heating and cooling
20 80% 3,500.00 $5,541.01 $— $4,358.00 $750.00 $0.145 3.53 1.07 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives. Based on 2012 average customer costs.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResHeatingCoolingDuctlessHeatPumpsSF_v1_3.xls. 2012.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 21
Energy Efficient Lighting
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 361,091 Test Benefit Cost Ratio
Program Incentives ............................................................. 765,745 I Utility Cost Test ................................... $ 6,315,418 $ 1,126,836 5.60
Total Utility Cost ................................................................. $ 1,126,836 P Total Resource Cost Test ................... 6,315,418 2,407,356 2.62
Ratepayer Impact Measure Test ......... 6,315,418 7,116,312 0.89
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 2,046,264 M Participant Cost Test ........................... 6,755,220 2,046,264 3.30

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 16,708,659 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 83,549,154 $ 6,315,418 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 6,315,418 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 5,989,476 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 100.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: No NTG. Deemed savings from the Regional Technical Forum (RTF) already accounts for realized energy savings.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 22 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
CFL Specialty Bulb—Retail 3-way CFL Incandescent bulb Bulb Lighting 7 100% 20.00 $9.97 $— $5.70 $2.00 $0.022 4.09 1.63 1
CFL Specialty Bulb—Retail Dimmable Incandescent bulb Bulb Lighting 7 100% 21.00 $10.47 $— $7.87 $2.00 $0.022 4.25 1.26 1
CFL Specialty Bulb—Retail Cold cathode candelabra primary Incandescent bulb Bulb Lighting 12 100% 14.00 $11.72 $— $5.67 $2.00 $0.022 5.08 1.96 1
CFL Specialty Bulb—Retail CFL candelabra & Torpedo Incandescent bulb Bulb Lighting 8 100% 14.00 $7.96 $— $1.74 $2.00 $0.022 3.45 3.89 1
CFL Specialty Bulb—Retail Dimmable reflector Incandescent bulb Bulb Lighting 8 100% 24.00 $13.65 $— $12.98 $2.00 $0.022 5.40 1.01 1
CFL Specialty Bulb—Retail Globe Incandescent bulb Bulb Lighting 6 100% 12.00 $5.13 $— $1.96 $2.00 $0.022 2.27 2.31 1
CFL Specialty Bulb—Retail Outdoor Incandescent bulb Bulb Lighting 5 100% 32.00 $11.38 $— $7.35 $2.00 $0.016 4.53 1.45 1
CFL Specialty Bulb—Retail Reflector CFL Incandescent bulb Bulb Lighting 8 100% 24.00 $13.65 $— $0.66 $2.00 $0.022 5.40 11.49 1
CFL Specialty Bulb—Retail Any specialty bulb Incandescent bulb Bulb Lighting 7 100% 17.00 $8.48 $— $1.49 $2.00 $0.022 3.57 4.54 1
CFL Spiral Bulb—Retailer Spiral bulb Incandescent bulb Bulb Lighting 6 100% 16.00 $6.84 $— $3.18 $0.50 $0.022 8.03 1.94 2
a Average measure life.
b No Net-to-Gross (NTG) percentage. Deemed savings from the RTF includes realization rate.
c Estimated kWh savings measured at the customer’s meter, excluding line losses. d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResSpecialtyCFL_v1_3.xlsm. Retail. Residential lighting. Any location. 2012.
2 RTF. ResCFLLighting_v2_2,.xlsm. Retail. Any Interior or Exterior Application. 2012.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 23
Energy House Calls
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 275,884 Test Benefit Cost Ratio
Program Incentives ............................................................. — I Utility Cost Test ................................... $ 1,125,669 $ 275,884 4.08
Total Utility Cost ................................................................. $ 275,884 P Total Resource Cost Test ................... 1,125,669 275,884 4.08
Ratepayer Impact Measure Test ......... 1,125,669 1,254,201 0.90
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ — M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 1,192,039 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 14,674,849 $ 1,407,087 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 1,407,087 S Participant Cost Test ................................ N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 1,222,897 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: Increased deemed savings from the RTF and lower administration costs increased program cost-effectiveness over 2011.
No participant cost.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 24 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
PTCS Duct Sealing Single wide (< =1,000 ft2) manufactured home duct tightness—PTCS duct sealing—heating zone 1 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 1,496.00 $1,653.43 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct
tightness—heating zone 1 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 1,433.00 $1,583.80 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 1 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 887.00 $980.34 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 2 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 2,361.00 $2,609.46 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 2 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 2,290.00 $2,530.99 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating
zone 2 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 1,664.00 $1,839.11 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 3 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 3,074.00 $3,397.49 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 3 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 3,023.00 $3,341.13 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Single wide (<=1,000 ft2) manufactured home duct tightness—heating zone 3 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 2,324.00 $2,568.57 $— $— $— $0.231 3.83 3.83 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 25
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
PTCS Duct Sealing Single (>1,000 ft2) manufactured home duct tightness—heating zone 3(electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 1,881.00 $2,078.95 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 1 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 1,799.00 $1,988.32 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 1 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 1,093.00 $1,208.02 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2)
manufactured home duct tightness—heating zone 2 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 2,898.00 $3,202.97 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 2 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 2,791.00 $3,084.71 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 2 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 2,022.00 $2,234.79 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 3 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 18 80% 3,710.00 $4,100.42 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct
tightness—heating zone 3 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 18 80% 3,645.00 $4,028.58 $— $— $— $0.231 3.83 3.83 1
PTCS Duct Sealing Other (>1,000 ft2) manufactured home duct tightness—heating zone 3 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 18 80% 2,813.00 $3,109.03 $— $— $— $0.231 3.83 3.83 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 26 Demand-Side Management 2012 Annual Report
e No participant cost.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResHeatingCoolingDuctSealingMH_v2_4.xlsm. 2012.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 27
ENERGY STAR® Homes Northwest
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 49,186 Test Benefit Cost Ratio
Program Incentives ............................................................. 404,000 I Utility Cost Test ................................... $ 784,903 $ 453,186 1.73
Total Utility Cost ................................................................. $ 453,186 P Total Resource Cost Test ................... 789,471 754,235 1.05
Ratepayer Impact Measure Test ......... 784,903 1,042,352 0.75
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 822,124 M Participant Cost Test ........................... 1,228,631 822,124 1.49

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 537,447 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 8,531,475 $ 1,090,143 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 1,090,143 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 818,286 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ 6,345 NEB Net-to-Gross (NTG) .............................................................................. 72.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: 2009 International Energy Conservation Code (IECC) adopted in Idaho in 2011.
Non-energy benefits include the NPV of avoided gas for ENERGY STAR gas-heated homes. Based on RTF's assumptions of therms saved per year.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 28 Demand-Side Management 2012 Annual Report
Year: 2012 Program: ENERGY STAR Homes Northwest Market Segment: Residential Program Type: Energy Efficiency

Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefitf
Gross Incremental Participant Costg Incentive/ Unit
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
ENERGY STAR home Home in Idaho or Montana with gas FAF and w/CAC—heating zone 1, cooling zone 3
Single-family home built to International Energy Conservation Code (IECC) 2009 Code, adopted 2011.
Home Residential 22 72% 696.00 $1,144.99 $649.10 $2,296.88 $400.00 $0.092 1.78 0.71 1, 2
ENERGY STAR home Home in Idaho or Montana with gas
FAF and w/CAC—heating zone 2, cooling zone 2
Single-family home built to IECC 2009
Code, adopted 2011.
Home Residential 20 72% 639.00 $982.61 $825.36 $2,296.88 $400.00 $0.092 1.54 0.71 1, 2
ENERGY STAR home Home in Idaho or Montana with gas FAF and w/CAC—heating zone 3, cooling zone 1
Single-family home built to IECC 2009 Code, adopted 2011.
Home Residential 19 72% 622.00 $920.69 $976.01 $2,296.88 $400.00 $0.092 1.45 0.75 1, 2
ENERGY STAR home Home in Idaho or Montana with heat pump—heating zone 1, cooling zone 3
Single-family home built to IECC 2009 Code, adopted 2011.
Home Residential 37 72% 3,778.00 $8,368.00 $— $3,940.71 $1,000.00 $0.092 4.47 1.74 1
ENERGY STAR home Home in Idaho or Montana built to the DHP TCO—heating zone 1, cooling zone 3
Single-family home built to IECC 2009 Code, adopted 2011.
Home Residential 37 72% 4,844.00 $10,729.12 $— $5,660.63 $1,000.00 $0.092 5.34 1.61 3
ENERGY STAR home Multifamily heat pump—heating zone 1, cooling
zone 3
Single-family home built to IECC 2009 Code, adopted
2011.
Home Residential 36 72% 1,294.00 $2,829.97 $— $2,309.61 $1,000.00 $0.092 1.82 0.99 4, 5
a Only heating system type and climate zone combinations with paid incentives in 2012 are displayed.
b Average measure life.
c Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
d Estimated kWh savings measured at the customer’s meter, excluding line losses.
e Sum of net present value (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 2011 IRP.
f Sum of NPV of avoided cost of gas.
g Incremental participant cost prior to customer incentives.
h Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals. i Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
j Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResNewSFEStarWAIDMT_v2_2.xls. 2012.
2 Measure not cost-effective. Removed from the program in 2012.
3 RTF. EStarNWSFHomes_DHPtco_WAIDMT_v1_0.xls. 2011.
4 RTF. ResMFEstarHomes2012_v1_1.xlsm. 2012.
5 Measure not cost-effective. Will monitor in 2013.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 29
Heating & Cooling Efficiency Program
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 124,081 Test Benefit Cost Ratio
Program Incentives ............................................................. 58,200 I Utility Cost Test ................................... $ 931,700 $ 182,281 5.11
Total Utility Cost ................................................................. $ 182,281 P Total Resource Cost Test ................... 931,700 577,681 1.61
Ratepayer Impact Measure Test ......... 931,700 789,742 1.18
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 552,449 M Participant Cost Test ........................... 817,526 552,449 1.48

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 688,855 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 8,956,781 $ 1,164,625 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 1,164,625 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 759,326 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 30 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Heating & Cooling Efficiency Program Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
A/C/Heat Pump Units Evaporative cooler single family Central A/C Unit Cooling 12 80% 416.00 $667.47 $— $— $150.00 $0.180 2.37 2.37 1
A/C/Heat Pump Units Evaporative cooler manufactured home Central A/C Unit Cooling 12 80% 309.00 $495.79 $— $— $150.00 $0.180 1.93 1.93 1
A/C/Heat Pump Units Evaporative cooler multi-family Central A/C Unit Cooling 12 80% 296.00 $474.93 $— $— $150.00 $0.180 1.87 1.87 1
A/C/Heat Pump Units
Open-loop, water source heat pump—14.00 EER 3.5 COP
Electric resistance Unit Heating and cooling
20 80% 8,927.00 $14,132.74 $— $10,792.00 $1,000.00 $0.180 4.34 1.08 2, 3
A/C/Heat Pump Units
Open-loop, water-source heat pump—3.5 COP
Oil/propane system Unit Heating and cooling
20 80% 8,927.00 $14,132.74 $— $10,792.00 $1,000.00 $0.180 4.34 1.08 2, 3
A/C/Heat Pump Units
New construction open-loop water-source heat pump—4.00 EER 3.5 COP
Electric resistance Unit Heating and cooling
20 80% 8,927.00 $14,132.74 $— $10,792.00 $1,000.00 $0.180 4.34 1.08 2, 3
A/C/Heat Pump Units
Open-loop water-source heat pump—14.00 EER 3.5 COP
Air-source heat pump Unit Heating and cooling
20 80% 2,648.00 $4,192.17 $— $4,435.00 $500.00 $0.180 3.43 0.81 2, 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.20 HSPF, all climates
Forced-air furnace w/o central A/C
Unit Heating and cooling
20 80% 5,138.00 $8,134.20 $— $3,667.00 $300.00 $0.180 5.31 1.66 1, 3
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 1
Forced-air furnace w/central A/C
Unit Heating and cooling
20 80% 5,306.00 $8,400.17 $— $3,857.00 $400.00 $0.180 4.96 1.63 3, 6
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 2
Forced air furnace w/central A/C
Unit Heating and cooling
20 80% 6,961.00 $11,020.28 $— $3,857.00 $400.00 $0.180 5.33 2.00 3, 6
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 3
Forced-air furnace w/central A/C
Unit Heating and cooling
20 80% 7,876.00 $12,468.86 $— $3,857.00 $400.00 $0.180 5.49 2.18 3, 6
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 1, cooling zone 3
Forced air furnace w/o central a/c
Unit Heating and cooling
20 80% 4,380.00 $6,934.18 $— $6,090.00 $400.00 $0.180 4.67 0.97 3, 5, 6
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 31
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 2, cooling zone 1
Forced air furnace w/o central a/c
Unit Heating and cooling
20 80% 6,719.00 $10,637.16 $— $6,090.00 $400.00 $0.180 5.29 1.38 3, 6
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 2, cooling zone 2
Forced air furnace w/o central a/c
Unit Heating and cooling
20 80% 6,451.00 $10,212.87 $— $6,090.00 $400.00 $0.180 5.23 1.34 3, 6
A/C/Heat
Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating
zone 2, cooling zone 3
Forced air furnace w/o central a/c
Unit Heating and cooling
20 80% 6,035.00 $9,554.28 $— $6,090.00 $400.00 $0.180 5.14 1.27 3, 6
A/C/Heat Pump Units
Single-family home HVAC conversions to heat pump 8.50 HSPF heating zone 3, cooling zone 1
Forced air furnace w/o central a/c
Unit Heating and cooling
20 80% 7,634.00 $12,085.73 $— $6,090.00 $400.00 $0.180 5.45 1.53 3, 6
A/C/Heat Pump Units
Existing single-family home heat pump—upgraded to 8.20 HSPF, all climates
Heat pump Unit Heating and cooling
20 80% 2,179.00 $3,449.67 $— $424.00 $200.00 $0.180 4.66 3.58 1, 4
A/C/Heat Pump Units
Existing single-family home heat pump—upgraded to 8.50 HSPF All Climates
Heat pump Unit Heating and cooling
20 80% 2,597.00 $4,111.43 $— $1,796.00 $250.00 $0.180 4.58 1.68 1, 4
A/C/Heat Pump Units
Existing single-family home heat pump—upgraded to
9.0 HSPF/14 SEER, heating zone 1
Heat pump Unit Heating and cooling
15 80% 128.00 $161.73 $— $59.04 $— $0.180 5.62 1.84 7, 8
A/C/Heat Pump Units
Existing single-family home heat pump—upgraded to 9.0 HSPF/14 SEER, heating zone 2
Heat pump Unit Heating and cooling
15 80% 116.00 $146.56 $— $59.04 $— $0.180 5.62 1.72 7, 8
A/C/Heat Pump Units
Existing single-family home heat pump—upgraded to 9.0 HSPF/14 SEER, heating zone 3
Heat pump Unit Heating and cooling
15 80% 115.00 $145.30 $— $59.04 $— $0.180 5.62 1.71 7, 8
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 32 Demand-Side Management 2012 Annual Report
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG)) 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 Costs based on average 2012 local contractor costs.
4 Costs based on incremental difference between technology and Regional Technical Forum (RTF) survey data
5 Measure not cost-effective due to high incremental costs. Will monitor in 2013.
6 Savings from RTF. Res_SFHPConversion_V2_6.xlsm.2012.
7 RTF. ResHeatingCoolingHeatPumpUpgradeSF_v2_8.xlsm.
8 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.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 33
Home Improvement Program
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 183,087 Test Benefit Cost Ratio
Program Incentives ............................................................. 202,004 I Utility Cost Test ................................... $ 920,542 $ 385,091 2.39
Total Utility Cost ................................................................. $ 385,091 P Total Resource Cost Test ................... 920,542 727,452 1.27
Ratepayer Impact Measure Test ......... 920,542 1,005,379 0.92
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 629,956 M Participant Cost Test ........................... 977,365 629,956 1.55

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 457,353 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 7,637,182 $ 1,150,677 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 1,150,677 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 775,361 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: The program was redesigned in 2012. Non-electrically heated homes were removed from the program after March 31, 2012. Existing attic insulation must be R20 or less and the final depth of R38 or greater.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 34 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Home Improvement Program Market Segment: Residential Program Type: Energy Efficiency

Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R0 to R19. Average heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R19
ft2
Heating & Cooling 45 80% 1.66 $4.11 $— $0.50 $0.15 $0.195 6.93 4.36 1
Single-family attic insulation R0 to R19. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R0 to R19 ft2 Heating & Cooling 45 80% 1.06 $2.62 $— $0.50 $0.15 $0.195 5.88 3.29 1
Single-family attic insulation R0 to R19. No electric
heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R0 to R19 ft2 Cooling 45 80% 0.11 $0.37 $— $0.50 $0.15 $0.195 1.71 0.65 1, 2
Single-family attic insulation R0 to R19. Zonal heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R19 ft2 Heating 45 80% 1.59 $3.15 $— $0.50 $0.15 $0.195 5.48 3.41 1
Single-family attic insulation R0 to R38. Average electric heating system w/o CAC. Heating zone 1, cooling zone 3
Attic Insulation R0 to R38 ft2 Heating 45 80% 2.06 $4.09 $— $0.50 $0.15 $0.195 5.93 3.93 1
Single-family attic insulation R0 to R38. Average electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic Insulation R0 to R38 ft2 Heating 45 80% 2.87 $5.70 $— $0.50 $0.15 $0.195 6.42 4.61 1
Single-family attic insulation R0 to R38. Average electric heating system w/o CAC. Heating zone 3, cooling zone 1
Attic Insulation R0 to R38 ft2 Heating 45 80% 3.49 $6.92 $— $0.50 $0.15 $0.195 6.67 4.99 1
Single-family attic insulation R0 to R38. Average
heating system w/CAC. Heating zone 1, cooling zone 3
Attic Insulation R0 to R38 ft2 Heating & Cooling 45 80% 2.28 $5.62 $— $0.50 $0.15 $0.195 7.58 5.15 1
Single-family attic insulation R0 to R38. Electric FAF Heating System w/ CAC. Heating zone 1, cooling zone 3
Attic Insulation R0 to R38 ft2 Heating & Cooling 45 80% 2.65 $6.55 $— $0.50 $0.15 $0.195 7.85 5.53 1
Single-family attic insulation R0 to R38. Electric FAF heating system w/o CAC. Heating zone 2, cooling zone 2
Attic Insulation R0 to R38 ft2 Heating 45 80% 3.29 $6.54 $— $0.50 $0.15 $0.195 6.60 4.88 1
Single-family attic insulation R0 to R38. Heat pump. Heating zone 1, cooling zone 3
Attic Insulation R0 to R38 ft2 Heating & Cooling 45 80% 1.44 $3.57 $— $0.50 $0.15 $0.195 6.61 4.01 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 35
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R0 to R38. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R0 to R38 ft2 Heating and cooling
45 80% 2.23 $5.50 $— $0.50 $0.15 $0.195 7.53 5.09 1
Single-family attic insulation R0 to R38. Heat pump. Heating zone 2, cooling zone 3
Attic insulation R0 to R38 ft2 Heating and cooling
45 80% 2.30 $5.68 $— $0.50 $0.15 $0.195 7.60 5.18 1
Single-family attic insulation R0 to R38. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R38 ft2 Cooling 45 80% 0.22 $0.75 $— $0.50 $0.15 $0.195 3.12 1.27 1
Single-family attic insulation R0 to R38. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R0 to R38 ft2 Cooling 45 80% 0.14 $0.49 $— $0.50 $0.15 $0.195 2.22 0.86 1, 2
Single-family attic insulation R0 to R38. Zonal
heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R38 ft2 Heating 45 80% 2.17 $4.32 $— $0.50 $0.15 $0.195 6.02 4.04 1
Single-family attic insulation R0 to R49. Average electric heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Heating 45 80% 2.19 $4.34 $— $0.50 $0.15 $0.195 6.03 4.06 1
Single-family attic insulation R0 to R49. Average electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R0 to R49 ft2 Heating 45 80% 3.05 $6.06 $— $0.50 $0.15 $0.195 6.51 4.73 1
Single-family attic insulation R0 to R49. Electric FAF heating system w/ CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Heating and cooling
45 80% 2.82 $6.96 $— $0.50 $0.15 $0.195 7.96 5.69 1
Single-family attic insulation R0 to R49. Electric FAF heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Heating 45 80% 2.59 $5.14 $— $0.50 $0.15 $0.195 6.28 4.40 1
Single-family attic insulation R0 to R49. Electric FAF
heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R0 to R49 ft2 Heating 45 80% 3.50 $6.95 $— $0.50 $0.15 $0.195 6.68 5.00 1
Single-family attic insulation R0 to R49. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Heating and cooling
45 80% 1.53 $3.78 $— $0.50 $0.15 $0.195 6.75 4.15 1
Single-family attic insulation R0 to R49. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R0 to R49 ft2 Heating and cooling
45 80% 2.36 $5.83 $— $0.50 $0.15 $0.195 7.64 5.24 1
Single-family attic insulation R0 to R49. Heat pump. Heating zone 2, cooling zone 3
Attic insulation R0 to R49 ft2 Heating and cooling
45 80% 2.44 $6.03 $— $0.50 $0.15 $0.195 7.71 5.32 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 36 Demand-Side Management 2012 Annual Report
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R0 to R49. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Cooling 45 80% 0.23 $0.80 $— $0.50 $0.15 $0.195 3.27 1.34 1
Single-family attic insulation R0 to R49. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R0 to R49 ft2 Cooling 45 80% 0.15 $0.52 $— $0.50 $0.15 $0.195 2.33 0.91 1, 2
Single-family attic insulation R0 to R49. Zonal heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R0 to R49 ft2 Heating 45 80% 2.31 $4.59 $— $0.50 $0.15 $0.195 6.11 4.17 1
Single-family attic insulation R0 to R49. Zonal heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R0 to R49 ft2 Heating 45 80% 3.69 $7.32 $— $0.50 $0.15 $0.195 6.74 5.10 1
Single-family attic insulation R19 to R30. Average
heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R30 ft2 Heating
and cooling
45 80% 0.59 $1.45 $— $0.50 $0.15 $0.195 4.39 2.13 1
Single-family attic insulation R19 to R30. Electric FAF heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R30 ft2 Heating and cooling
45 80% 0.52 $1.28 $— $0.50 $0.15 $0.195 4.09 1.93 1
Single-family attic insulation R19 to R30. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R19 to R30 ft2 Heating and cooling
45 80% 0.28 $0.68 $— $0.50 $0.15 $0.195 2.68 1.13 1
Single-family attic insulation R19 to R30. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R19 to R30 ft2 Heating and cooling
45 80% 0.42 $1.04 $— $0.50 $0.15 $0.195 3.59 1.62 1
Single-family attic insulation R19 to R30. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R30 ft2 Cooling 45 80% 0.04 $0.15 $— $0.50 $0.15 $0.195 0.74 0.27 1, 2
Single-family attic insulation R19 to R30. No electric
heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R30 ft2 Cooling 45 80% 0.03 $0.09 $— $0.50 $0.15 $0.195 0.48 0.17 1, 2
Single-family attic insulation R19 to R38. Average Electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R38 ft2 Heating 45 80% 0.78 $1.54 $— $0.50 $0.15 $0.195 4.09 2.12 1
Single-family attic insulation R19 to R38. Average Electric heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R19 to R38 ft2 Heating 45 80% 0.94 $1.87 $— $0.50 $0.15 $0.195 4.49 2.44 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 37
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R19 to R38. Average heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R38 ft2 Heating and cooling
45 80% 0.61 $1.52 $— $0.50 $0.15 $0.195 4.50 2.21 1
Single-family attic insulation R19 to R38. Electric FAF heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R38 ft2 Heating and cooling
45 80% 0.72 $1.77 $— $0.50 $0.15 $0.195 4.89 2.49 1
Single-family attic insulation R19 to R38. Electric FAF heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R19 to R38 ft2 Heating 45 80% 1.07 $2.12 $— $0.50 $0.15 $0.195 4.74 2.66 1
Single-family attic insulation R19 to R38. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R19 to R38 ft2 Heating and cooling
45 80% 0.38 $0.94 $— $0.50 $0.15 $0.195 3.36 1.49 1
Single-family attic insulation R19 to R38. Heat pump.
Heating zone 2, cooling zone 2
Attic insulation R19 to R38 ft2 Heating
and cooling
45 80% 0.58 $1.43 $— $0.50 $0.15 $0.195 4.36 2.11 1
Single-family attic insulation R19 to R38. Heat pump. Heating zone 2, cooling zone 3
Attic insulation R19 to R38 ft2 Heating and cooling
45 80% 0.60 $1.48 $— $0.50 $0.15 $0.195 4.45 2.17 1
Single-family attic insulation R19 to R38. Heat pump. Heating zone 3, cooling zone 1
Attic insulation R19 to R38 ft2 Heating and cooling
45 80% 0.76 $1.88 $— $0.50 $0.15 $0.195 5.03 2.60 1
Single-family attic insulation R19 to R38. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R38 ft2 Cooling 45 80% 0.06 $0.20 $— $0.50 $0.15 $0.195 0.99 0.36 1, 2
Single-family attic insulation R19 to R38. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R38 ft2 Cooling 45 80% 0.04 $0.13 $— $0.50 $0.15 $0.195 0.65 0.23 1, 2
Single-family attic insulation R19 to R38. Zonal heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R38 ft2 Heating 45 80% 0.65 $1.29 $— $0.50 $0.15 $0.195 3.72 1.85 1
Single-family
attic insulation
R19 to R38. Zonal
heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation
R19 to R38
ft2 Heating 45 80% 0.59 $1.17 $— $0.50 $0.15 $0.195 3.53 1.72 1
Single-family attic insulation R19 to R38. Zonal heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R38 ft2 Heating 45 80% 0.79 $1.58 $— $0.50 $0.15 $0.195 4.14 2.16 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 38 Demand-Side Management 2012 Annual Report
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R19 to R49. Average electric heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating 45 80% 0.69 $1.36 $— $0.50 $0.15 $0.195 3.84 1.93 1
Single-family attic insulation R19 to R49. Average electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Heating 45 80% 0.96 $1.90 $— $0.50 $0.15 $0.195 4.52 2.47 1
Single-family attic insulation R19 to R49. Average electric heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R19 to R49 ft2 Heating 45 80% 1.16 $2.31 $— $0.50 $0.15 $0.195 4.90 2.81 1
Single-family attic insulation R19 to R49. Average heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.76 $1.87 $— $0.50 $0.15 $0.195 5.03 2.59 1
Single-family attic insulation R19 to R49. Average
heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Heating
and cooling
45 80% 1.00 $2.48 $— $0.50 $0.15 $0.195 5.73 3.17 1
Single-family attic insulation R19 to R49. Electric FAF heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.89 $2.19 $— $0.50 $0.15 $0.195 5.43 2.91 1
Single-family attic insulation R19 to R49. Electric FAF heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 1.15 $2.85 $— $0.50 $0.15 $0.195 6.08 3.48 1
Single-family attic insulation R19 to R49. Electric FAF heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating 45 80% 0.81 $1.62 $— $0.50 $0.15 $0.195 4.19 2.20 1
Single-family attic insulation R19 to R49. Electric FAF heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Heating 45 80% 1.11 $2.20 $— $0.50 $0.15 $0.195 4.81 2.72 1
Single-family attic insulation R19 to R49. Electric
FAF heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R19 to R49 ft2 Heating 45 80% 1.32 $2.62 $— $0.50 $0.15 $0.195 5.15 3.05 1
Single-family attic insulation R19 to R49. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.47 $1.16 $— $0.50 $0.15 $0.195 3.84 1.78 1
Single-family attic insulation R19 to R49. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.71 $1.76 $— $0.50 $0.15 $0.195 4.88 2.48 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 39
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R19 to R49. Heat pump. Heating zone 2, cooling zone 3
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.74 $1.83 $— $0.50 $0.15 $0.195 4.97 2.55 1
Single-family attic insulation R19 to R49. Heat pump. Heating zone 3, cooling zone 1
Attic insulation R19 to R49 ft2 Heating and cooling
45 80% 0.93 $2.31 $— $0.50 $0.15 $0.195 5.56 3.01 1
Single-family attic insulation R19 to R49. No electric heating system w/ CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Cooling 45 80% 0.07 $0.25 $— $0.50 $0.15 $0.195 1.20 0.44 1, 2
Single-family attic insulation R19 to R49. No electric heating system w/ CAC. Heating zone 2, cooling zone 2
Attic insulation R19 to R49 ft2 Cooling 45 80% 0.05 $0.16 $— $0.50 $0.15 $0.195 0.79 0.29 1, 2
Single-family attic insulation R19 to R49. Zonal
heating system w/ CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating
and cooling
45 80% 0.80 $1.97 $— $0.50 $0.15 $0.195 5.16 2.70 1
Single-family attic insulation R19 to R49. Zonal heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R19 to R49 ft2 Heating 45 80% 0.73 $1.44 $— $0.50 $0.15 $0.195 3.96 2.02 1
Single-family attic insulation R19 to R49. Zonal heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R19 to R49 ft2 Heating 45 80% 1.16 $2.31 $— $0.50 $0.15 $0.195 4.90 2.81 1
Single-family attic insulation R30 to R38. Average electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R38 ft2 Heating 45 80% 0.21 $0.43 $— $0.50 $0.15 $0.195 1.78 0.72 1, 3
Single-family attic insulation R30 to R38. Average electric heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R30 to R38 ft2 Heating 45 80% 0.26 $0.52 $— $0.50 $0.15 $0.195 2.06 0.86 1, 3
Single-family attic insulation R30 to R38. Average
heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R38 ft2 Heating
and cooling
45 80% 0.17 $0.42 $— $0.50 $0.15 $0.195 1.83 0.72 1, 3
Single-family attic insulation R30 to R38. Electric FAF heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R38 ft2 Heating and cooling
45 80% 0.20 $0.49 $— $0.50 $0.15 $0.195 2.08 0.84 1, 3
Single-family attic insulation R30 to R38. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R30 to R38 ft2 Heating and cooling
45 80% 0.10 $0.26 $— $0.50 $0.15 $0.195 1.22 0.46 1, 3
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 40 Demand-Side Management 2012 Annual Report
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R30 to R38. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R30 to R38 ft2 Heating and cooling
45 80% 0.16 $0.39 $— $0.50 $0.15 $0.195 1.73 0.68 1, 3
Single-family attic insulation R30 to R38. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R38 ft2 Cooling 45 80% 0.02 $0.05 $— $0.50 $0.15 $0.195 0.29 0.10 1, 2
Single-family attic insulation R30 to R38. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R38 ft2 Cooling 45 80% 0.01 $0.03 $— $0.50 $0.15 $0.195 0.18 0.06 1, 2
Single-family attic insulation R30 to R49. Average electric heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R49 ft2 Heating 45 80% 0.28 $0.56 $— $0.50 $0.15 $0.195 2.20 0.93 1, 3
Single-family attic insulation R30 to R49. Average
electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Heating 45 80% 0.40 $0.79 $— $0.50 $0.15 $0.195 2.77 1.24 1
Single-family attic insulation R30 to R49. Average heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R49 ft2 Heating and cooling
45 80% 0.31 $0.77 $— $0.50 $0.15 $0.195 2.93 1.26 1
Single-family attic insulation R30 to R49. Average heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Heating and cooling
45 80% 0.41 $1.02 $— $0.50 $0.15 $0.195 3.55 1.60 1
Single-family attic insulation R30 to R49. Electric FAF heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Heating 45 80% 0.46 $0.91 $— $0.50 $0.15 $0.195 3.04 1.40 1
Single-family attic insulation R30 to R49. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R30 to R49 ft2 Heating and cooling
45 80% 0.19 $0.48 $— $0.50 $0.15 $0.195 2.03 0.82 1, 3
Single-family attic insulation R30 to R49. Heat pump.
Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Heating
and cooling
45 80% 0.29 $0.72 $— $0.50 $0.15 $0.195 2.79 1.19 1
Single-family attic insulation R30 to R49. Heat pump. Heating zone 2, cooling zone 3
Attic insulation R30 to R49 ft2 Heating and cooling
45 80% 0.30 $0.75 $— $0.50 $0.15 $0.195 2.86 1.22 1
Single-family attic insulation R30 to R49. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R49 ft2 Cooling 45 80% 0.03 $0.10 $— $0.50 $0.15 $0.195 0.52 0.19 1, 2
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 41
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R30 to R49. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Cooling 45 80% 0.02 $0.06 $— $0.50 $0.15 $0.195 0.33 0.12 1, 2
Single-family attic insulation R30 to R49. Zonal heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R30 to R49 ft2 Heating 45 80% 0.30 $0.60 $— $0.50 $0.15 $0.195 2.29 0.98 1, 3
Single-family attic insulation R30 to R49. Zonal heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R30 to R49 ft2 Heating 45 80% 0.41 $0.81 $— $0.50 $0.15 $0.195 2.81 1.27 1
Single-family attic insulation R30 to R49. Zonal heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R30 to R49 ft2 Heating 45 80% 0.48 $0.96 $— $0.50 $0.15 $0.195 3.14 1.46 1
Single-family attic insulation R38 to R49. Average
electric heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R38 to R49 ft2 Heating 45 80% 0.18 $0.36 $— $0.50 $0.15 $0.195 1.56 0.62 1, 3
Single-family attic insulation R38 to R49. Average electric heating system w/o CAC. Heating zone 3, cooling zone 1
Attic insulation R38 to R49 ft2 Heating 45 80% 0.22 $0.44 $— $0.50 $0.15 $0.195 1.82 0.74 1, 3
Single-family attic insulation R38 to R49. Average heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R38 to R49 ft2 Heating and cooling
45 80% 0.14 $0.35 $— $0.50 $0.15 $0.195 1.59 0.62 1, 3
Single-family attic insulation R38 to R49. Average heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R38 to R49 ft2 Heating and cooling
45 80% 0.19 $0.47 $— $0.50 $0.15 $0.195 2.01 0.80 1, 3
Single-family attic insulation R38 to R49. Average heating system w/CAC. Heating zone 2, cooling zone 3
Attic insulation R38 to R49 ft2 Heating and cooling
45 80% 0.19 $0.48 $— $0.50 $0.15 $0.195 2.05 0.82 1, 3
Single-family attic insulation R38 to R49. Average
heating system w/CAC. Heating zone 3, cooling zone 1
Attic insulation R38 to R49 ft2 Heating
and cooling
45 80% 0.23 $0.56 $— $0.50 $0.15 $0.195 2.30 0.94 1, 3
Single-family attic insulation R38 to R49. Electric FAF heating system w/o CAC. Heating zone 1, cooling zone 3
Attic insulation R38 to R49 ft2 Heating 45 80% 0.15 $0.31 $— $0.50 $0.15 $0.195 1.36 0.53 1, 3
Single-family attic insulation R38 to R49. Heat pump. Heating zone 1, cooling zone 3
Attic insulation R38 to R49 ft2 Heating and cooling
45 80% 0.09 $0.22 $— $0.50 $0.15 $0.195 1.04 0.39 1, 3
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 42 Demand-Side Management 2012 Annual Report
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family attic insulation R38 to R49. Heat pump. Heating zone 2, cooling zone 2
Attic insulation R38 to R49 ft2 Heating and cooling
45 80% 0.13 $0.33 $— $0.50 $0.15 $0.195 1.50 0.58 1, 3
Single-family attic insulation R38 to R49. No electric heating system w/CAC. Heating zone 1, cooling zone 3
Attic insulation R38 to R49 ft2 Cooling 45 80% 0.01 $0.05 $— $0.50 $0.15 $0.195 0.24 0.09 1, 2
Single-family attic insulation R38 to R49. No electric heating system w/CAC. Heating zone 2, cooling zone 2
Attic insulation R38 to R49 ft2 Cooling 45 80% 0.01 $0.03 $— $0.50 $0.15 $0.195 0.15 0.05 1, 3
Single-family attic insulation R38 to R49. Zonal heating system w/o CAC. Heating zone 2, cooling zone 2
Attic insulation R38 to R49 ft2 Heating 45 80% 0.19 $0.37 $— $0.50 $0.15 $0.195 1.59 0.63 1, 3
Single-family
floor insulation
R0 to R30. Electric FAF
heating system w/CAC. Heating zone 1, cooling zone 3
Floor
insulation R0 to R30
ft2 Heating
and cooling
45 80% 1.48 $3.66 $— $1.00 $0.50 $0.195 3.71 2.47 1
Single-family floor insulation
R0 to R30. Electric FAF heating system w/CAC. Heating zone 3, cooling zone 1
Floor insulation R0 to R30
ft2 Heating and cooling
45 80% 2.37 $5.85 $— $1.00 $0.50 $0.195 4.87 3.44 1
Single-family floor insulation
R0 to R30. Electric FAF heating system w/o CAC. Heating zone 3
Floor insulation R0 to R30
ft2 Heating 45 80% 2.42 $4.80 $— $1.00 $0.50 $0.195 3.95 2.80 1
Single-family floor insulation
R0 to R30. Heat pump. Heating zone 1, cooling zone 3.
Floor insulation R0 to R30
ft2 Heating and cooling
45 80% 0.61 $1.50 $— $1.00 $0.50 $0.195 1.94 1.18 1
Single-family floor insulation
R0 to R30. Heat pump. Heating zone 2, cooling zone 2.
Floor insulation R0 to R30
ft2 Heating and cooling
45 80% 0.97 $2.39 $— $1.00 $0.50 $0.195 2.78 1.76 1
Single-family floor insulation
R0 to R30. Heat pump. Heating zone 2, cooling zone 3.
Floor insulation R0 to R30
ft2 Heating and cooling
45 80% 0.97 $2.40 $— $1.00 $0.50 $0.195 2.79 1.76 1
Single-family floor
insulation
R0 to R30. Heat pump. Heating zone 3, cooling
zone 1.
Floor insulation R0
to R30
ft2 Heating and
cooling
45 80% 1.33 $3.29 $— $1.00 $0.50 $0.195 3.46 2.27 1
Single-family floor insulation
R0 to R30. Zonal heating system w/o CAC. Heating zone 1, cooling zone 3
Floor insulation R0 to R30
ft2 Heating 45 80% 1.46 $2.90 $— $1.00 $0.50 $0.195 2.95 1.96 1
Single-family floor insulation
R0 to R30. Zonal heating system w/o CAC. Heating zone 2, cooling zone 2
Floor insulation R0 to R30
ft2 Heating 45 80% 1.91 $3.79 $— $1.00 $0.50 $0.195 3.48 2.38 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 43
Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unitg
Admin Cost ($/kWh)h UC Ratioi TRC Ratioj Source
Single-family floor insulation
R0 to R30. Zonal heating system w/o CAC. Heating zone 3, cooling zone 1
Floor insulation R0 to R30
ft2 Heating 45 80% 2.31 $4.58 $— $1.00 $0.50 $0.195 3.86 2.71 1
Single-family wall insulation R0 to R11. Electric FAF heating system w/o CAC. Heating zone 2, cooling zone 2
Wall insulation R0 to R11 ft2 Heating 45 80% 2.43 $4.83 $— $0.83 $0.50 $0.195 3.97 3.12 1
Single-family wall insulation R0 to R11. Heat pump . Heating zone 1, cooling zone 3
Wall insulation R0 to R11 ft2 Heating & Cooling 45 80% 0.95 $2.36 $— $0.83 $0.50 $0.195 2.75 1.98 1
Single-family wall insulation R0 to R11. Heat pump . Heating zone 2, cooling zone 2
Wall insulation R0 to R11 ft2 Heating & Cooling 45 80% 1.53 $3.79 $— $0.83 $0.50 $0.195 3.79 2.85 1
Single-family wall insulation R0 to R11. Zonal
heating system w/o CAC. Heating zone 1, cooling zone 3
Wall insulation R0 to R11 ft2 Heating 45 80% 1.60 $3.17 $— $0.83 $0.50 $0.195 3.12 2.36 1
Single-family wall insulation R0 to R11. Zonal heating system w/o CAC. Heating zone 2, cooling zone 3
Wall insulation R0 to R11 ft2 Heating 45 80% 2.13 $4.23 $— $0.83 $0.50 $0.195 3.70 2.87 1
a Only heating system type and climate zone combinations with paid incentives in 2012 are displayed.
b Average measure life.
c Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
d Estimated kWh savings measured at the customer’s meter, excluding line losses.
e Sum of net present value (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 2011 IRP.
f Incremental participant cost prior to customer incentives. Based on 2012 median customer costs.
g Properly sealed ducts required for the program. If additional air and duct sealing was required, an additional incentive of $0.50/ln ft was paid. 2012 incentives still averaged $0.15/sq ft for attic and $0.50/sq ft for floor and wall insulation.
h Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
i Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives). j Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResSFWx_v2_5_IdahoPower_withCAC_ByCoolingZone.xlsm. 2011.
2 Measure not cost-effective. Non-electrically heated homes removed from the program in April 2012.
3 Measure not cost-effective. Measure no longer qualifies under current program design effective April 2012. Home must have existing insulation less than R20.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 44 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 45
Home Products Program
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 156,708 Test Benefit Cost Ratio
Program Incentives ............................................................. 502,324 I Utility Cost Test ................................... $ 777,732 $ 659,032 1.18
Total Utility Cost ................................................................. $ 659,032 P Total Resource Cost Test ................... 819,082 769,774 1.06
Ratepayer Impact Measure Test ......... 777,732 1,265,497 0.61
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 640,752 M Participant Cost Test ........................... 1,312,093 640,752 2.05

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 887,222 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 9,503,226 $ 972,165 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 972,165 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 758,081 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ 51,688 NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: Non-energy benefits include the NPV of avoided gas for ENERGY STAR® clothes washers. Based on RTF’s assumptions of therms saved per year.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 46 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Home Products Program Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefite
Gross Incremental Participant Costf Incentive/ Unit
Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Clothes Washer ENERGY STAR® clothes washer, any MEF, any DHW, any dryer
Old clothes washers Washer Washer 14 80% 37.30 $39.34 $1.12 $74.64 $50.00 $0.342 0.50 0.39 1, 2
Refrigerator ENERGY STAR refrigerator, bottom freezer w/ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 45.00 $59.72 $- $18.52 $30.00 $0.342 1.05 1.32 3
Refrigerator ENERGY STAR
refrigerator, bottom freezer w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 40.00 $53.09 $- $10.65 $30.00 $0.342 0.97 1.51 3
Refrigerator ENERGY STAR refrigerator, side-by-side w/ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 44.00 $58.39 $- $36.70 $30.00 $0.342 1.04 0.93 3, 4
Refrigerator ENERGY STAR refrigerator, side-by-side w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 51.00 $67.68 $- $43.66 $30.00 $0.342 1.14 0.93 3, 4
Refrigerator ENERGY STAR refrigerator, top freezer w/ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 40.00 $53.09 $- $14.29 $30.00 $0.342 0.97 1.37 3
Refrigerator ENERGY STAR refrigerator, top freezer w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 45.00 $59.72 $- $16.30 $30.00 $0.342 1.05 1.39 3
Refrigerator ENERGY STAR refrigerator Old refrigerator Refrigerator First refrigerator 20 80% 44.00 $58.39 $- $22.54 $30.00 $0.342 1.04 1.20 3
Freezer ENERGY STAR freezer, no tiers, chest, any defrost
Old freezer Freezer Freezer 22 80% 29.00 $41.43 $- $3.43 $20.00 $0.342 1.11 1.99 5
Freezer ENERGY STAR freezer, no tiers, upright, automatic defrost
Old freezer Freezer Freezer 22 80% 56.00 $80.00 $- $5.83 $20.00 $0.342 1.63 2.30 5
Freezer ENERGY STAR freezer, no tiers, upright, manual defrost
Old freezer Freezer Freezer 22 80% 28.00 $40.00 $- $2.92 $20.00 $0.342 1.08 2.01 5
Freezer ENERGY STAR freezer, no tiers, any upright
Old freezer Freezer Freezer 22 80% 47.00 $67.14 $- $4.97 $20.00 $0.342 1.49 2.23 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 47
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefite
Gross Incremental Participant Costf Incentive/ Unit
Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Freezer ENERGY STAR freezer, no tiers, any freezer
Old freezer Freezer Freezer 22 80% 40.00 $57.14 $- $4.34 $20.00 $0.342 1.36 2.16 5
Lighting ENERGY STAR LED light fixture Incandescent light fixture Fixture Lighting 12 100% 35.00 $29.29 $- $54.41 $15.00 $0.342 1.09 0.44 6, 7
Lighting ENERGY STAR light fixture, weighted average all
Incandescent light fixture Fixture Lighting 15 100% 49.00 $50.20 $- $22.74 $15.00 $0.342 1.58 1.27 8
Lighting ENERGY STAR ceiling fan light kits Incandescent ceiling fan light fixture
Fixture Lighting 6 100% 32.00 $13.69 $- $44.00 $15.00 $0.342 0.53 0.25 7, 9
Lighting ENERGY STAR ceiling fan Old ceiling fan Fixture Cooling 10 80% 59.00 $81.54 $- $86.00 $20.00 $0.342 1.62 0.70 7, 10
Low-flow showerhead Low-flow showerhead 2.0 gpm, any shower,
any water heating, retail
Showerhead 2.2 gpm or higher
Showerhead Water
heating
10 80% 66.78 $47.46 $6.16 $27.78 $7.00 $0.004 5.22 1.80 11
Low-flow showerhead Low-flow showerhead 1.75 gpm, any shower, any water heating, retail
Showerhead 2.2 gpm or higher
Showerhead Water
heating
10 80% 99.77 $70.91 $9.20 $27.78 $7.00 $0.004 7.67 2.67 11
Low-flow showerhead Low-flow showerhead 1.5 gpm, any shower, any water heating, retail
Showerhead 2.2 gpm or higher
Showerhead Water
heating
10 80% 129.12 $91.77 $11.95 $27.78 $7.00 $0.004 9.77 3.44 11
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.No NTG percentage for lighting measures from the RTF.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (NPV) of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
e Sum of NPV of avoided cost of gas.
f Incremental participant cost prior to customer incentives.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals. Admin for mail in rebate and retailer markdown calculated separately.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResClothesWasherSF_v3.xls. Any DHW, Any Dryer. 2012. Adjusted savings by changing Electric Water Heating saturation from 64% to 52% and Electric dryer saturation from 82% to 95% to match IPC mix.
2 Measure not cost-effective. Measure removed from the program in 2013.
3 Measure RTF. ResRefrigerator_v2_1.xls. 2011.
4 Measure not cost-effective due to high admin costs ($/kWh). Will monitor in 2013. 5 RTF. ResFreezer_v2_2.xlsm. 2012.
6 RTF. ResSpecialtyLighting_v1_1.xlsml. Any Location. 2011.
7 Measure not cost-effective. Removed from the program in 2012.
8 RTF. ResCFLLighting_v2_2.xlsm. 2012. Measure moved to Energy Efficient Lighting in 2012.
9 RTF. ResCFLLighting_v2_2.xlsm. 2012. Savings equivalent to 2 retail CFL bulbs at 16 kWh/year.
10 ADM Associates, Inc. Impact Evaluation of 2010 Home Products Program. 2011.
11 RTF. ResShowerheads_v2_1.xlsm. 2011. Adjusted savings by changing Electric Water Heating saturation from 64% to 52% to match Idaho Power mix.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 48 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 49
Rebate Advantage
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 24,241 Test Benefit Cost Ratio
Program Incentives ............................................................. 13,000 I Utility Cost Test ................................... $ 228,152 $ 37,241 6.13
Total Utility Cost ................................................................. $ 37,241 P Total Resource Cost Test ................... 228,152 62,977 3.51
Ratepayer Impact Measure Test ......... 228,152 227,301 1.00
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 47,670 M Participant Cost Test ........................... 250,575 47,670 5.26

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 187,108 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 2,669,689 $ 285,190 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 285,190 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 237,575 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 50 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
ENERGY STAR® manufactured home
New ENERGY STAR manufactured home w/electric FAF—heating zone 1
Manufactured home built to Housing and Urban Development (HUD) code.
Home Heating 26 80% 5,420.00 $7,944.52 $— $1,577.51 $500.00 $0.130 5.28 3.08 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home
w/electric FAF—heating zone 2
Manufactured home built to HUD code.
Home Heating 27 80% 6,847.00 $10,294.73 $— $1,577.51 $500.00 $0.130 5.92 3.66 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/electric FAF—heating zone 3
Manufactured home built to HUD code.
Home Heating 27 80% 8,057.00 $12,114.01 $— $1,577.51 $500.00 $0.130 6.26 4.02 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 1, cooling zone 1
Manufactured home built to HUD code.
Home Heating and cooling
23 80% 3,128.00 $5,458.83 $— $1,577.51 $500.00 $0.130 4.82 2.47 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 1, cooling zone 2
Manufactured home built to HUD code.
Home Heating and cooling
23 80% 3,172.00 $5,535.61 $— $1,577.51 $500.00 $0.130 4.85 2.50 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 1, cooling zone 3
Manufactured home built to HUD code.
Home Heating and cooling
23 80% 3,254.00 $5,678.72 $— $1,577.51 $500.00 $0.130 4.92 2.55 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 2, cooling zone 1
Manufactured home built to HUD code.
Home Heating and cooling
25 80% 4,346.00 $8,005.66 $— $1,577.51 $500.00 $0.130 6.01 3.32 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 2, cooling zone 2
Manufactured home built to HUD code.
Home Heating and cooling
25 80% 4,390.00 $8,086.71 $— $1,577.51 $500.00 $0.130 6.04 3.35 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 2, cooling zone 3
Manufactured home built to HUD code.
Home Heating and cooling
25 80% 4,472.00 $8,237.76 $— $1,577.51 $500.00 $0.130 6.09 3.39 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 51
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 3, cooling zone 1
Manufactured home built to HUD code.
Home Heating and cooling
26 80% 5,516.00 $10,410.57 $— $1,577.51 $500.00 $0.130 6.84 4.01 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 3, cooling zone 2
Manufactured home built to HUD code.
Home Heating and cooling
26 80% 5,560.00 $10,493.61 $— $1,577.51 $500.00 $0.130 6.87 4.03 1
ENERGY STAR manufactured home
New ENERGY STAR manufactured home w/heat pump—heating zone 3, cooling zone 3
Manufactured home built to HUD code.
Home Heating and cooling
26 80% 5,642.00 $10,648.37 $— $1,577.51 $500.00 $0.130 6.91 4.07 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals. g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. NewMH_EStar_EcoRated_v1_2.xls. 2011.

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Page 52 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 53
See ya later, refrigerator®
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 512,406 Test Benefit Cost Ratio
Program Incentives ............................................................. 100,740 I Utility Cost Test ................................... $ 981,675 $ 613,146 1.60
Total Utility Cost ................................................................. $ 613,146 P Total Resource Cost Test ................... 981,675 613,146 1.60
Ratepayer Impact Measure Test ......... 981,675 1,469,128 0.67
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ — M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 1,576,426 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 11,509,388 $ 981,675 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 981,675 S Participant Cost Test ................................ N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 855,982 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 100.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Line Losses ........................................................................................... 10.90%
Notes: No NTG. Deemed savings from the Regional Technical Forum (RTF) already accounts for net realized energy savings. No participant costs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 54 Demand-Side Management 2012 Annual Report
Year: 2012 Program: See ya later, refrigerator® Market Segment: Residential Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Freezer Recycling Freezer removal and decommissioning
— Freezer Freezer 6 100% 555.00 $245.31 $— $— $30.00 $0.333 1.14 1.14 1
Refrigerator Recycling Refrigerator removal and decommissioning
— Refrigerator Second refrigerator 9 100% 482.00 $315.61 $— $— $30.00 $0.333 1.66 1.66 1
a Average measure life.
b No Net-to-Gross (NTG) percentage. Deemed savings from the RTF includes realization rate.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e No participant cost.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals. g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResFridgeFreezeDecommissioning_v2.4.xlsm. 2012.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 55
Weatherization Assistance for Qualified Customers
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 276,074 Test Benefit Cost Ratio
CAP Agency Payments ....................................................... 1,094,065 Utility Cost Test ................................... $ 1,188,802 $ 1,407,271 0.84
Total Utility Cost ................................................................. $ 1,370,141 P Total Resource Cost Test ................... 1,326,144 1,857,076 0.71
Idaho Power Indirect Overhead Expense Allocation—2.71% $ 37,131 OH Ratepayer Impact Measure Test ......... 1,188,802 2,230,437 0.53
Additional State Funding ....................................................... $ 449,804 M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P + OH
2012 Annual Gross Energy (kWh) ................. 648,304 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + OH + M
NPV Cumulative Energy (kWh) ..................... 9,260,173 $ 1,080,729 Ratepayer Impact Measure Test .............. = S * NTG = P + OH+ (B * NTG)
10% Credit (Northwest Power Act) ................ 108,073 Participant Cost Test ................................ N/A N/A
Total Electric Savings .................................... $ 1,188,802 S
Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 823,166 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Electric Benefits ........................................................ Net-to-Gross (NTG) .............................................................................. 100.00%
Health and Safety ......................................................... $ 119,061 Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Repair ........................................................................... 18,281 Line Losses ........................................................................................... 10.90%
Other ............................................................................ —
Non-Energy Benefits Total ................................................ $ 137,342 NEB
Notes: Savings based on average annual realized savings of 2,684 kWh per home. Realization rate of 29% applied to non-profit buildings’ energy savings. Savings are derived from billing analysis of the 2011 projects.
Program cost-effectiveness incorporated Idaho Public Utilities Commission (IPUC) staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Claimed 100 percent 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.

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Page 56 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 57
Weatherization Solutions for Eligible Customers
Segment: Residential
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 149,200 Test Benefit Cost Ratio
CAP Agency Payments ....................................................... 921,356 Utility Cost Test ................................... $ 472,118 $ 1,099,568 0.43
Total Utility Cost ................................................................. $ 1,070,556 P Total Resource Cost Test ................... 515,238 1,099,568 0.47
Idaho Power Indirect Overhead Expense Allocation—2.71% $ 29,012 OH Ratepayer Impact Measure Test ......... 472,118 1,426,478 0.33
Additional State Funding ....................................................... $ — M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P + OH
2012 Annual Gross Energy (kWh) ................. 257,466 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + OH + M
NPV Cumulative Energy (kWh) ..................... 3,677,564 $ 429,198 Ratepayer Impact Measure Test .............. = S * NTG = P + OH+ (B * NTG)
10% Credit (Northwest Power Act) ................ 42,920 Participant Cost Test ................................ N/A N/A
Total Electric Savings .................................... $ 472,118 S
Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 326,910 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Electric Benefits ........................................................ Net-to-Gross (NTG) .............................................................................. 100.00%
Health and Safety ......................................................... $ 35,320 Average 2012 Customer Segment Rate/kWh ........................................ $0.079
Repair ........................................................................... 7,800 Line Losses ........................................................................................... 10.90%
Other ............................................................................ —
Non-Energy Benefits Total ................................................ $ 43,120 NEB
Notes: Savings based on average annual realized savings of 1,826 kWh per home. Savings are derived from billing analysis of the 2011 projects.
Program cost-effectiveness incorporated Idaho Public Utilities Commission (IPUC) staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Claimed 100 percent 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.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 58 Demand-Side Management 2012 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 59
Building Efficiency
Segment: Commercial
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 270,527 Test Benefit Cost Ratio
Program Incentives ............................................................. 1,322,045 I Utility Cost Test ................................... $ 14,457,004 $ 1,592,572 9.08
Total Utility Cost ................................................................. $ 1,592,572 P Total Resource Cost Test ................... 14,457,004 6,822,421 2.10
Ratepayer Impact Measure Test ......... 14,457,004 9,434,227 1.53
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 7,934,356 M Participant Cost Test ........................... 11,124,114 7,934,356 1.40

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 20,450,037 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 198,825,500 $ 18,071,255 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 18,071,255 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 9,802,070 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.050
Line Losses ........................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 60 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Building Efficiency Market Segment: Commercial Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Lighting Controls
Interior light load reduction–10–19% below code
— ft2 Lighting 11 96% 0.38 $0.32 $— $0.05 $0.05 $0.011 5.64 5.64 1
Lighting Controls
Interior light load reduction–20% or more below code
— ft2 Lighting 11 96% 1.09 $0.91 $— $0.10 $0.15 $0.011 5.41 7.69 1
Lighting Controls
Exterior light load
reduction–15% or more below code
— kW Outdoor lighting 11 96% 4,059.00 $2,453.88 $— $205.00 $200.00 $0.011 9.63 9.44 2
Lighting Controls Daylight photo controls — ft2 Lighting 8 96% 0.61 $0.38 $— $0.25 $0.25 $0.011 1.41 1.40 3
Lighting Controls Occupancy sensors — Sensor Lighting 8 96% 289.99 $180.31 $— $77.00 $25.00 $0.011 6.14 2.22 3
Sign Lighting High efficiency exit signs — Signs Lighting 16 96% 333.00 $389.07 $— $31.52 $7.50 $0.011 33.46 10.91 3
A/C/Heat Pump Units Premium efficiency HVAC unit — Ton HVAC 15 80% 386.72 $523.10 $— $122.22 $50.00 $0.011 7.71 3.74 1
A/C/Heat Pump Units
Additional HVAC unit efficiency bonus
— Ton HVAC 15 80% 181.78 $245.89 $— $81.50 $25.00 $0.011 7.29 2.72 1
A/C/Heat Pump Units Efficient chillers — Ton HVAC 15 80% 154.28 $208.69 $— $75.00 $20.00 $0.011 7.69 2.54 2
Economizers Air-side economizers — Ton HVAC 15 80% 300.00 $405.80 $— $170.00 $75.00 $0.011 4.15 2.10 3
Reflective Roofing Reflective roof coating — ft2 HVAC 15 80% 0.41 $0.55 $— $0.35 $0.05 $0.011 8.14 1.51 3
Efficient Windows High performance windows — ft2 HVAC 30 80% 1.01 $2.19 $— $0.74 $0.50 $0.011 3.42 2.49 3
Automated Control Systems
Energy
management control systems
— ft2 HVAC 14 96% 1.24 $1.59 $— $1.00 $0.30 $0.011 4.85 1.54 3
Automated Control Systems Demand controlled ventilation
— Cubic feet/ minute
HVAC 10 96% 1.31 $1.26 $— $0.60 $0.50 $0.011 2.34 1.98 3
Variable Speed Controls Variable speed drives — hp HVAC 15 96% 985.02 $1,332.40 $— $187.00 $60.00 $0.011 18.06 6.64 3
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 61
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Savings calculated from Idaho Power engineering estimates and research. Participant costs calculated based on Idaho Power Demand-Side management Potential Study by Nexant, Inc. 2 Savings and costs calculated from Idaho Power engineering estimates and research. 3 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 62 Demand-Side Management 2012 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 63
Custom Efficiency
Segment: Industrial
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 913,115 Test Benefit Cost Ratio
Program Incentives ............................................................. 6,179,466 I Utility Cost Test ................................... $ 33,080,183 $ 7,092,581 4.66
Total Utility Cost ................................................................. $ 7,092,581 P Total Resource Cost Test ................... 33,080,183 11,151,894 2.97
Ratepayer Impact Measure Test ......... 33,080,183 17,738,942 1.86
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 12,062,528 M Participant Cost Test ........................... 21,608,974 12,062,528 1.79

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 54,253,106 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 527,475,863 $ 47,942,294 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 47,942,294 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 15,429,508 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 69.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.030
Line Losses ........................................................................................... 10.90%
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 for motors between 25 to 5,000 hp. Did not pay any incentives for motors greater than 600 hp in 2012.
Commercial and industrial motor rewinds are paid under Custom Efficiency.
NTG of 69 percent from CPUC DEER NTFR Update Process for 2006-2007 Programs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 64 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Custom Efficiency—Green Motors Market Segment: Industrial Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind: Motor size 15 hp
Green Motors Program Rewind: Motor size 15 hp
Standard rewind practice
Motor MF_Motors 12 69% 274.00 $236.80 $— $160.14 $30.00 $0.050 3.74 1.22 1
Green Motors Program Rewind: Motor size 20 hp
Green Motors Program Rewind: Motor size 20 hp
Standard rewind practice
Motor MF_Motors 12 69% 363.00 $313.71 $— $178.67 $40.00 $0.050 3.72 1.41 1
Green Motors
Program Rewind: Motor size 25 hp
Green Motors
Program Rewind: Motor size 25 hp
Standard
rewind practice
Motor MF_Motors 11 69% 535.00 $426.30 $— $204.14 $50.00 $0.050 3.83 1.61 1
Green Motors Program Rewind: Motor size 30 hp
Green Motors Program Rewind: Motor size 30HP
Standard rewind practice
Motor MF_Motors 11 69% 575.00 $458.17 $— $224.21 $60.00 $0.050 3.56 1.56 1
Green Motors Program Rewind: Motor size 40 hp
Green Motors Program Rewind: Motor size 40HP
Standard rewind practice
Motor MF_Motors 11 69% 672.00 $535.46 $— $273.99 $80.00 $0.050 3.25 1.49 1
Green Motors Program Rewind: Motor size 50 hp
Green Motors Program Rewind: Motor size 50HP
Standard rewind practice
Motor MF_Motors 11 69% 729.00 $580.88 $— $303.32 $100.00 $0.050 2.94 1.45 1
Green Motors Program Rewind: Motor size 60 hp
Green Motors Program Rewind: Motor size 60HP
Standard rewind practice
Motor MF_Motors 9 69% 971.00 $641.22 $— $357.73 $120.00 $0.050 2.62 1.33 1
Green Motors
Program Rewind: Motor size 70 hp
Green Motors
Program Rewind: Motor size 70HP
Standard
rewind practice
Motor MF_Motors 9 69% 1,009.00 $666.31 $— $386.67 $150.00 $0.050 2.29 1.26 1
Green Motors Program Rewind: Motor size 100 hp
Green Motors Program Rewind: Motor size 100HP
Standard rewind practice
Motor MF_Motors 9 69% 1,558.00 $1,028.85 $— $479.67 $200.00 $0.050 2.55 1.51 1
Green Motors Program Rewind: Motor size 125 hp
Green Motors Program Rewind: Motor size 125HP
Standard rewind practice
Motor MF_Motors 10 69% 1,891.00 $1,379.95 $— $538.71 $250.00 $0.050 2.76 1.75 1
Green Motors Program Rewind: Motor size 150 hp
Green Motors Program Rewind: Motor size 150HP
Standard rewind practice
Motor MF_Motors 10 69% 2,254.00 $1,644.84 $— $600.07 $300.00 $0.050 2.75 1.83 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 65
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind: Motor size 200 hp
Green Motors Program Rewind: Motor size 200HP
Standard rewind practice
Motor MF_Motors 10 69% 2,987.00 $2,179.75 $— $722.40 $400.00 $0.050 2.74 1.95 1
Green Motors Program Rewind: Motor size 250 hp
Green Motors Program Rewind: Motor size 250HP
Standard rewind practice
Motor MF_Motors 8 69% 4,397.00 $2,592.01 $— $928.48 $500.00 $0.050 2.48 1.76 1
Green Motors Program Rewind: Motor size 300 hp
Green Motors Program Rewind: Motor size 300HP
Standard rewind practice
Motor MF_Motors 8 69% 5,269.00 $3,106.05 $— $938.51 $600.00 $0.050 2.48 1.95 1
Green Motors Program Rewind: Motor size 350 hp
Green Motors Program Rewind: Motor size 350HP
Standard rewind practice
Motor MF_Motors 8 69% 6,147.00 $3,623.63 $— $983.66 $700.00 $0.050 2.48 2.08 1
Green Motors
Program Rewind: Motor size 400 hp
Green Motors
Program Rewind: Motor size 400HP
Standard
rewind practice
Motor MF_Motors 8 69% 7,005.00 $4,129.42 $— $1,098.66 $800.00 $0.050 2.48 2.10 1
Green Motors Program Rewind: Motor size 450 hp
Green Motors Program Rewind: Motor size 450HP
Standard rewind practice
Motor MF_Motors 8 69% 7,859.00 $4,632.85 $— $1,200.92 $900.00 $0.050 2.47 2.13 1
Green Motors Program Rewind: Motor size 500 hp
Green Motors Program Rewind: Motor size 500HP
Standard rewind practice
Motor MF_Motors 8 69% 8,732.00 $5,147.48 $— $1,297.40 $1,000.00 $0.050 2.47 2.16 1
Green Motors Program Rewind: Motor size 600 hp
Green Motors Program Rewind: Motor size 600HP
Standard rewind practice
Motor MF_Motors 7 69% 12,279.00 $6,353.27 $— $1,911.88 $1,200.00 $0.050 2.42 1.90 1
a Average measure life.
b Net-to-Gross (NTG) percentage. CPUC DEER NTFR Update Process for 2006-2007 Programs.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives. Based on 2012 average customer costs. f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. IndGreenMotorsRewind_v1_3.xlsm. 2012.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 66 Demand-Side Management 2012 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 67
Easy Upgrades
Segment: Industrial
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 929,859 Test Benefit Cost Ratio
Program Incentives ............................................................. 4,483,988 I Utility Cost Test ................................... $ 29,386,668 $ 5,413,847 5.43
Total Utility Cost ................................................................. $ 5,413,847 P Total Resource Cost Test ................... 29,386,668 8,479,336 3.47
Ratepayer Impact Measure Test ......... 29,386,668 21,353,535 1.38
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 8,315,849 M Participant Cost Test ........................... 24,408,598 8,315,849 2.94

Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S * NTG = P
2012 Annual Gross Energy (kWh) ................. 41,568,672 Total Resource Cost Test ......................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ..................... 404,151,444 $ 36,733,335 Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Total Electric Savings .................................... $ 36,733,335 S Participant Cost Test ................................ = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings................................. $ 19,924,610 B Discount Rate .......................................................................................
Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Non-Utility Rebates/Incentives .......................................... $ — NUI Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ......................................................... $ — NEB Net-to-Gross (NTG) .............................................................................. 80.00%
Average 2012 Customer Segment Rate/kWh ........................................ $0.050
Line Losses ........................................................................................... 10.90%
Notes: Includes Easy Upgrades and Comprehensive Lighting energy savings and costs.
Measure inputs from Evergreen Consulting Group or Idaho Power Demand-Side Management Potential Study by Nexant, Inc. unless otherwise noted.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 68 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Easy Upgrades Market Segment: Commercial Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Standard T8s 2-foot or 3-foot T8s and electronic ballast (one or more lamps)
2-foot or 3-foot T12 (includes U-bend)
Fixture Lighting 11 96% 106.40 $89.15 $— $40.92 $8.00 $0.022 8.28 2.04 1
Standard T8s 1 lamp 4-foot T8 and electronic ballast
1 lamp 4-foot T12 Fixture Lighting 11 96% 59.50 $49.85 $— $28.40 $12.00 $0.022 3.60 1.65 1
Standard T8s 1 or 2 lamp 4-foot
T8s and electronic ballasts
2 lamp 4-foot T12 Fixture Lighting 11 96% 108.50 $90.91 $— $37.60 $14.00 $0.022 5.33 2.23 1
Standard T8s 2 or 3 lamp 4-foot T8s and electronic ballast
3 lamp 4-foot T12 Fixture Lighting 11 96% 176.75 $148.09 $— $54.45 $18.00 $0.022 6.50 2.50 1
Standard T8s 2, 3, or 4 lamp 4-foot T8s and electronic ballasts
4 lamp 4-foot T12 Fixture Lighting 11 96% 236.83 $198.43 $— $59.83 $22.00 $0.022 7.00 3.00 1
Standard T8s 1 or 2 lamp 6-foot T8s and electronic ballast
1 or 2 lamp 6-foot T12 Fixture Lighting 12 96% 121.33 $110.16 $— $49.33 $14.00 $0.022 6.34 2.09 1
Standard T8s 1 or 2 lamp 6-foot T8s and electronic ballast (slimline and HO)
1 or 2 lamp 6-foot T12 HO/VHO
Fixture Lighting 12 96% 377.03 $342.32 $— $81.55 $14.00 $0.022 14.74 3.77 1
Standard T8s 1 or 2 lamp 8-foot T8s and electronic ballast
1 or 2 lamp 8-foot T12 Fixture Lighting 12 96% 116.67 $105.92 $— $58.47 $12.00 $0.022 6.98 1.72 1
Standard T8s 2, 3, or 4 lamp 8-foot T8s and electronic ballast
3 or 4 lamp 8-foot T12 Fixture Lighting 12 96% 262.50 $238.33 $— $101.66 $24.00 $0.022 7.68 2.19 1
Standard T8s 1 or 2 lamp 8-foot T8s and electronic ballast (slimline and HO)
1 or 2 lamp 8-foot T12 HO/VHO
Fixture Lighting 12 96% 525.91 $477.48 $— $67.57 $12.00 $0.022 19.45 5.96 1
Standard T8s 2, 3, or 4 lamp 8-foot T8s and electronic ballast (slimline and HO)
3 or 4 lamp 8-foot T12 HO/VHO
Fixture Lighting 12 96% 1,195.59 $1,085.49 $— $95.00 $24.00 $0.022 20.72 8.80 1
Standard T8s 2 or 4 lamp 4-foot T8s and electronic ballast (tandem/retrofit)
1 or 2 lamp 8-foot T12 Fixture Lighting 11 96% 121.33 $101.66 $— $53.07 $22.00 $0.022 3.96 1.79 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 69
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Standard T8s 2 or 4 lamp 4-foot T8s and electronic ballast (tandem/retrofit)
1 or 2 lamp 8-foot T12 HO/VHO
Fixture Lighting 11 96% 540.87 $453.17 $— $54.81 $30.00 $0.022 10.38 6.62 1
High Performance T8s
1 lamp 4-foot T8 and electronic ballast
1 lamp 4-foot T12 Fixture Lighting 12 96% 80.50 $73.09 $— $62.98 $22.00 $0.022 2.95 1.11 1
High Performance T8s
1 or 2 lamp 4-foot HP T8s and electronic ballast
2 lamp 4-foot T12 Fixture Lighting 12 96% 129.86 $117.90 $— $60.13 $24.00 $0.022 4.21 1.84 1
High Performance T8s
2 or 3 lamp 4-foot HP T8s and electronic ballast
3 lamp 4-foot T12 Fixture Lighting 12 96% 203.97 $185.19 $— $67.23 $32.00 $0.022 4.87 2.53 1
High Performance T8s
2, 3, or 4 lamp 4-foot HP T8s and electronic ballast
4 lamp 4-foot T12 Fixture Lighting 12 96% 262.83 $238.63 $— $67.32 $34.00 $0.022 5.76 3.19 1
High
Performance T8s
2 or 4 lamp 4-foot
HP T8s and electronic ballast (tandem/retrofit)
1 or 2 lamp
8-foot T12
Fixture Lighting 12 96% 171.07 $155.32 $— $68.86 $34.00 $0.022 3.95 2.09 1
High Performance T8s
2 or 4 lamp 4-foot HP T8s and electronic ballast (tandem/retrofit)
1 or 2 lamp 8-foot T12 HO/VHO
Fixture Lighting 12 96% 567.38 $515.13 $— $74.54 $45.00 $0.022 8.60 5.76 1
T5 (Non-HO) 1 or 2 lamp 4-foot T5s and electronic ballast
1 or 2 lamp 4-foot T12 Fixture Lighting 11 96% 102.67 $86.02 $— $50.30 $14.00 $0.022 5.08 1.62 1
T5 (Non-HO) 2, 3, or 4 lamp 4-foot T5's and electronic ballast
3 or 4 lamp 4-foot T12 Fixture Lighting 11 96% 185.50 $155.42 $— $90.34 $24.00 $0.022 5.31 1.63 1
T5/T8 High Bay (New Fixture)
4 lamp 4-foot T8s and electronic ballast
Fixture (lamp & ballast) using ≥ 200 W
Fixture Lighting 12 96% 574.58 $521.67 $— $153.91 $75.00 $0.022 5.71 3.06 1
T5/T8 High Bay (New Fixture)
6 lamp 4-foot T8s and electronic ballast or 2, 3, or 4 lamp 4-foot
T5 HO's and electronic ballast
Fixture (lamp and ballast) using 200 to 399 W
Fixture Lighting 12 96% 400.47 $363.59 $— $184.82 $75.00 $0.022 4.16 1.84 1
T5/T8 High Bay (New Fixture)
6 or 8 lamp 4-foot T8s and electronic ballast or 4 or 6 lamp 4-foot T5 HO's and electronic ballast
Fixture (lamp and ballast) using ≥ 400 W
Fixture Lighting 12 96% 966.27 $877.29 $— $210.34 $110.00 $0.022 6.42 3.70 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 70 Demand-Side Management 2012 Annual Report
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
T5/T8 High Bay (New Fixture)
10 or 12 lamp 4-foot T8's and electronic ballast or 8 or 10 lamp 4-foot T5HO's and electronic ballast
Fixture (lamp and ballast) 751 to 1100 W
Fixture Lighting 12 96% 2,366.70 $2,148.76 $— $386.65 $180.00 $0.022 8.89 4.79 1
Compact Fluorescents (CFLs)
Screw-in compact fluorescent ≤ 32 W
Fixture using ≥ 60 input W Fixture Lighting 6 96% 98.00 $46.03 $— $23.00 $2.00 $0.022 10.63 1.82 1
CFLs Screw-in compact fluorescent 33 to 59 W
Fixture using ≥ 100 input W Fixture Lighting 6 96% 143.50 $67.41 $— $31.00 $4.00 $0.022 9.04 1.96 1
CFLs Screw-in compact fluorescent ≥ 60 W
Fixture using ≥ 150 input W Fixture Lighting 6 96% 175.00 $82.20 $— $29.00 $20.00 $0.022 3.31 2.43 1
CFLs Screw-in cold-cathode ≤ 32 W Fixture using ≥ 60 input W Fixture Lighting 6 96% 175.88 $82.62 $— $35.38 $4.00 $0.022 10.08 2.09 1
CFLs Hard-wired compact fluorescent ≤ 49 W and electronic ballasts
Fixture using ≥ 90 input W Fixture Lighting 6 96% 262.78 $123.44 $— $85.00 $30.00 $0.022 3.31 1.34 1
CFLs Hard-wired compact fluorescent 50 to 99 W and electronic ballasts
Fixture using ≥ 150 input W Fixture Lighting 6 96% 471.10 $221.29 $— $104.50 $40.00 $0.022 4.22 1.89 1
Light Emitting Diodes (LEDs) Screw-in or pin-based LED ≤ 10 W
Fixture using ≥ 40 input W Fixture Lighting 12 96% 105.00 $95.33 $— $45.00 $10.00 $0.022 7.43 1.99 1
Ceramic/Pulse Start Metal Halide
150 to 250 input W metal halide Fixture (lamp & ballast) using ≥ 295 input W
Fixture Lighting 12 96% 570.50 $517.97 $— $185.00 $30.00 $0.022 11.69 2.60 1
Ceramic/Pulse
Start Metal Halide
251 to 360 input W metal halide Fixture (lamp
& ballast) using ≥ 450 input W
Fixture Lighting 12 96% 499.63 $453.62 $— $217.50 $55.00 $0.022 6.60 1.96 1
Ceramic/Pulse Start Metal Halide
361+ input W metal halide Fixture (lamp & ballast) using ≥ 600 input W
Fixture Lighting 12 96% 2,033.50 $1,846.25 $— $245.00 $105.00 $0.022 11.84 6.24 1
LED Exits LED exit sign or equivalent (5 W or less)
Exit sign using ≥ 18 W Fixture Lighting 16 96% 88.67 $103.59 $— $68.69 $25.00 $0.022 3.69 1.44 1
Lighting Controls Wall switch occupancy sensor Manual or no prior control Fixture Lighting 10 96% 149.30 $114.66 $— $90.00 $35.00 $0.022 2.88 1.21 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 71
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Lighting Controls Wall or ceiling mount occupancy sensor
Manual or no prior control Fixture Lighting 10 96% 472.17 $362.63 $— $130.00 $50.00 $0.022 5.76 2.54 1
Lighting Controls Fixture mount occupancy sensor Manual or no prior control Fixture Lighting 10 96% 252.22 $193.71 $— $100.00 $50.00 $0.022 3.35 1.80 1
Lighting Controls Interior photocell control (dimming, step-dimming or switching)
Manual or no prior control Fixture Lighting 10 96% 379.42 $291.40 $— $130.00 $40.00 $0.022 5.79 2.08 1
Lighting Controls Auto-off time switch or time clock control (minimum of 100 watts connected to load)
Manual or no prior control Fixture Lighting 10 96% 272.74 $209.46 $— $125.00 $40.00 $0.022 4.37 1.58 1
A/C/Heat Pump Units PTAC/PTHP unit, min 12 EER Standard
PTAC/PTHP unit
Unit HVAC 12 80% 562.50 $631.17 $— $255.00 $50.00 $0.022 8.10 2.23 2
A/C/Heat Pump Units 5 ton or less 1-phase AC unit, min 14 SEER
Standard 1-5 ton AC unit Ton HVAC 15 80% 239.04 $323.34 $— $50.00 $25.00 $0.022 8.55 5.15 3
A/C/Heat Pump Units 5 ton or less 1-phase AC unit, min 15 SEER
Standard 5 ton or less AC unit
Ton HVAC 15 80% 278.88 $377.23 $— $100.00 $50.00 $0.022 5.38 3.14 3
A/C/Heat Pump Units 5 ton or less 1-phase AC unit, min 16 SEER
Standard 5 ton or less AC unit
Ton HVAC 15 80% 313.74 $424.39 $— $150.00 $75.00 $0.022 4.15 2.39 3
A/C/Heat Pump Units 5 ton or less 3-phase AC unit, min 13 SEER
Standard 1-5 ton AC unit Ton HVAC 15 80% 415.50 $562.03 $— $75.00 $50.00 $0.022 7.60 5.68 2
A/C/Heat Pump Units 5 ton or less 3-phase AC unit, min 14 SEER
Standard 5 ton or less AC unit
Ton HVAC 15 80% 239.04 $323.34 $— $75.00 $75.00 $0.022 3.22 3.22 3
A/C/Heat Pump Units 5 ton or less 3-phase AC unit, min 15 SEER
Standard 5 ton or less AC unit
Ton HVAC 15 80% 278.88 $377.23 $— $150.00 $100.00 $0.022 2.84 2.07 3
A/C/Heat Pump Units 6-10 ton AC unit, min 11 EER Standard 6-10 ton AC unit Ton HVAC 15 80% 120.09 $162.44 $— $100.00 $50.00 $0.022 2.47 1.40 3
A/C/Heat Pump Units 11-19 ton AC unit, min 10.8 EER Standard 11-19 ton AC unit Ton HVAC 15 80% 124.95 $169.01 $— $100.00 $50.00 $0.022 2.56 1.46 3
A/C/Heat Pump Units 20 ton or more AC unit, min 10 EER Standard 20 ton+ AC unit Ton HVAC 15 80% 92.96 $125.74 $— $75.00 $50.00 $0.022 1.93 1.40 3
Economizers Air-side economizer control addition
No prior control Ton HVAC 15 80% 300.00 $405.80 $— $170.00 $75.00 $0.022 3.98 2.06 3, 4
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 72 Demand-Side Management 2012 Annual Report
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Economizers Water-side economizer control addition
No prior control Ton HVAC 10 80% 1,199.10 $1,147.31 $— $463.00 $75.00 $0.022 9.05 2.23 3, 4
Economizers Air-side economizer system repair
Non-functional Economizer
Unit HVAC 15 80% 4,499.29 $6,086.04 $— $630.00 $250.00 $0.022 13.95 7.46 3, 4
Evaporative Coolers/ Pre-Coolers
Pre-cooler added to condenser Standard air cooled AC unit
Ton HVAC 10 80% 832.30 $796.35 $— $200.00 $100.00 $0.022 5.38 3.21 3
Evaporative Coolers/ Pre-Coolers
Retrofit to direct evaporative cooler Replacing standard AC unit
Ton HVAC 15 80% 902.52 $1,220.81 $— $400.00 $200.00 $0.022 4.44 2.57 3
Evaporative Coolers/ Pre-Coolers
Retrofit to indirect evaporative cooler Replacing standard AC unit
Ton HVAC 15 80% 676.89 $915.61 $— $550.00 $300.00 $0.022 2.33 1.42 3
Variable
Speed Fans/Pumps
Variable speed drive, fan Single speed
HVAC system fan
HP HVAC 15 96% 1,078.29 $1,458.57 $— $187.00 $60.00 $0.022 16.72 6.81 3, 4
Variable Speed Fans/Pumps
Variable speed drive, pump Single speed HVAC system pump
HP HVAC 15 96% 891.74 $1,206.23 $— $187.00 $60.00 $0.022 14.54 5.75 3, 4
Programmable Thermostats 7-day, two-stage setback thermostat
Manual thermostat Unit HVAC 11 80% 4,209.94 $4,377.82 $— $174.76 $40.00 $0.022 26.41 14.57 3, 4
Automated Control Systems
Energy management control systems
Manual controls Square Feet HVAC 14 80% 1.20 $1.53 $— $0.95 $0.30 $0.022 3.76 1.45 3, 4
Automated Control Systems
Control system reprogramming/optimization
Automated control system
Square Feet HVAC 4 80% 0.75 $0.30 $— $0.15 $0.10 $0.022 2.06 1.53 2, 4
Automated Control Systems
Lodging room occupancy control system
Manual controls Room HVAC 12 80% 900.00 $1,009.87 $— $75.00 $50.00 $0.022 11.57 9.00 2, 4
NEMA Premium Efficiency TM Motors
1 hp Motor, min 85.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 57.25 $70.04 $— $50.00 $20.00 $0.022 3.16 1.34 3, 5
NEMA
Premium Efficiency Motors
1.5 hp Motor, min
86.5% efficiency
Same or
larger hp standard motor
Motor Motor 15 96% 71.38 $87.34 $— $73.00 $25.00 $0.022 3.16 1.15 3, 5
NEMA Premium Efficiency Motors
2 hp Motor, min 86.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 94.86 $116.06 $— $65.00 $30.00 $0.022 3.47 1.70 3, 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 73
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
NEMA Premium Efficiency Motors
3 hp Motor, min 89.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 145.98 $178.61 $— $73.00 $35.00 $0.022 4.49 2.30 3, 5
NEMA Premium Efficiency Motors
5 hp Motor, min 89.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 182.82 $223.67 $— $99.00 $40.00 $0.022 4.88 2.13 3, 5
NEMA Premium Efficiency Motors
7.5 hp Motor, min 91.7% efficiency Same or larger hp standard motor
Motor Motor 15 96% 443.33 $542.41 $— $71.00 $55.00 $0.022 8.04 6.50 3, 5
NEMA Premium Efficiency Motors
10 hp Motor, min 91.7% efficiency Same or larger hp standard motor
Motor Motor 15 96% 544.74 $666.48 $— $90.00 $70.00 $0.022 7.80 6.32 3, 5
NEMA
Premium Efficiency Motors
15 hp Motor, min 93.0% efficiency Same or
larger hp standard motor
Motor Motor 15 96% 720.26 $881.23 $— $168.00 $90.00 $0.022 7.99 4.68 3, 5
NEMA Premium Efficiency Motors
20 hp Motor, min 93.0% efficiency Same or larger hp standard motor
Motor Motor 15 96% 996.47 $1,219.17 $— $165.00 $110.00 $0.022 8.87 6.34 3, 5
NEMA Premium Efficiency Motors
25 hp Motor, min 93.6% efficiency Same or larger hp standard motor
Motor Motor 15 96% 1,604.32 $1,962.86 $— $329.00 $130.00 $0.022 11.40 5.29 3, 5
NEMA Premium Efficiency Motors
30 hp Motor, min 94.1% efficiency Same or larger hp standard motor
Motor Motor 15 96% 1,819.00 $2,225.52 $— $331.00 $150.00 $0.022 11.24 5.87 3, 5
NEMA Premium Efficiency Motors
40 hp Motor, min 94.1% efficiency Same or larger hp standard motor
Motor Motor 15 96% 2,048.95 $2,506.86 $— $398.00 $180.00 $0.022 10.69 5.54 3, 5
NEMA
Premium Efficiency Motors
50 hp Motor, min 94.5% efficiency Same or
larger hp standard motor
Motor Motor 15 96% 2,120.15 $2,593.98 $— $384.00 $220.00 $0.022 9.34 5.87 3, 5
NEMA Premium Efficiency Motors
60 hp Motor, min 95.0% efficiency Same or larger hp standard motor
Motor Motor 15 96% 2,931.36 $3,586.48 $— $332.00 $280.00 $0.022 9.99 8.73 3, 5
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 74 Demand-Side Management 2012 Annual Report
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
NEMA Premium Efficiency Motors
75 hp Motor, min 95.4% efficiency Same or larger hp standard motor
Motor Motor 15 96% 3,007.97 $3,680.21 $— $366.00 $350.00 $0.022 8.49 8.19 3, 5
NEMA Premium Efficiency Motors
100 hp Motor, min 95.4% efficiency Same or larger hp standard motor
Motor Motor 15 96% 4,460.07 $5,456.83 $— $555.00 $420.00 $0.022 10.11 8.09 3, 5
NEMA Premium Efficiency Motors
125 hp Motor, min 95.4% efficiency Same or larger hp standard motor
Motor Motor 15 96% 6,428.45 $7,865.12 $— $961.00 $550.00 $0.022 10.92 6.95 3, 5
NEMA Premium Efficiency Motors
150 hp Motor, min 95.8% efficiency Same or larger hp standard motor
Motor Motor 15 96% 7,233.63 $8,850.25 $— $609.00 $650.00 $0.022 10.50 11.04 3, 5
NEMA
Premium Efficiency Motors
200 hp Motor, min 96.2% efficiency Same or
larger hp standard motor
Motor Motor 15 96% 10,077.27 $12,329.40 $— $964.00 $750.00 $0.022 12.18 10.06 3, 5
Downsizing Bonus Downsizing motors during retrofit
10-200 hp existing motor HP Motor 15 96% 12.60 $15.42 $— $- $3.00 $0.022 4.52 4.52 3, 5
ECM Motors ECM Motor Standard induction motor
Motor Motor 15 96% 421.80 $516.07 $— $110.00 $30.00 $0.022 12.61 4.27 3
Variable Speed Controls
Variable speed drives Standard motor, 5-200 hp
HP Motor 10 96% 3,542.00 $3,039.38 $— $187.00 $60.00 $0.022 21.16 11.23 3
Premium Windows SHGC of .30 or less and U-Factor .30 or less.
Standard window Square Feet HVAC 30 80% 1.38 $2.98 $— $1.50 $1.50 $0.022 1.56 1.56 3
Efficient Windows SHGC of .40 or less and U-Factor .42 or less.
Standard window Square Feet HVAC 30 80% 0.92 $1.99 $— $0.68 $1.00 $0.022 1.56 2.08 3
Window Shading Adding window shade screen No screen or other shading Square Feet HVAC 10 80% 2.10 $2.01 $— $1.00 $0.50 $0.022 2.94 1.70 3
Reflective Roofing Adding reflective roof treatment Non-reflective low pitch roof Square Feet HVAC 15 80% 0.40 $0.54 $— $0.32 $0.05 $0.022 7.36 1.58 3
Roof/Ceiling Insulation Increasing to R24 min insulation Insulation level, R11 or less
Square Feet HVAC 40 80% 0.92 $2.28 $— $0.83 $0.10 $0.022 15.18 2.59 3
Roof/Ceiling Insulation Increasing to R38 min insulation Insulation level, R11 or less
Square Feet HVAC 40 80% 1.46 $3.61 $— $0.95 $0.20 $0.022 12.46 3.46 3
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 75
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Wall Insulation Increase to R11 min insulation Insulation level, R5 or less
Square Feet HVAC 40 80% 1.04 $2.59 $— $0.62 $0.05 $0.022 28.38 3.95 3
Wall Insulation Increase to R19 min insulation Insulation level, R5 or less
Square Feet HVAC 40 80% 2.44 $6.04 $— $0.74 $0.10 $0.022 31.46 7.25 3
Refrigeration Cases Efficient, medium-temp open case Standard medium-temp open case
Linear Foot Refrigeration 16 96% 148.18 $163.65 $— $100.00 $20.00 $0.022 6.75 1.57 3
Refrigeration Cases Efficient, medium-temp reach-in Standard medium-temp open case
Linear Foot Refrigeration 16 96% 564.94 $623.91 $— $100.00 $100.00 $0.022 5.33 5.33 3
Refrigeration Cases Efficient, low-temp reach-in (reach-in) Standard low-temp reach-in Linear Foot Refrigeration 16 96% 478.36 $528.30 $— $100.00 $150.00 $0.022 3.16 4.51 3
Refrigeration Cases Efficient, low-temp reach-in (open case)
Standard low-temp open case
Linear Foot Refrigeration 16 96% 1,208.00 $1,334.11 $— $100.00 $150.00 $0.022 7.25 9.96 3
Refrigeration Cases Efficient, low-temp reach-in (coffin case)
Standard low-temp coffin case
Linear Foot Refrigeration 16 96% 703.42 $776.85 $— $100.00 $55.00 $0.022 10.58 6.56 3
Refrigeration Cases Vertical night covers No covers present Linear Foot Refrigeration 5 96% 148.00 $54.05 $— $9.00 $9.00 $0.022 4.23 4.23 3
Refrigeration Cases Horizontal night covers No covers present Linear Foot Refrigeration 5 96% 59.00 $21.55 $— $9.00 $5.00 $0.022 3.28 2.04 3
Refrigeration Cases Refrigeration line insulation No insulation present Linear Foot Refrigeration 11 96% 17.00 $13.40 $— $2.00 $1.00 $0.022 9.36 5.51 3
Refrigeration Cases Door gasket--walk-in No or damaged door gasket
Linear Foot Refrigeration 4 96% 137.50 $39.88 $— $4.00 $2.00 $0.022 7.62 5.51 3
Refrigeration Cases Door gasket--reach-in Damaged door gasket Linear Foot Refrigeration 4 96% 92.50 $26.83 $— $4.00 $1.00 $0.022 8.49 4.35 3
Refrigeration Cases Auto-closer--walk-in No or damaged auto closer, low-temp
Unit Refrigeration 8 96% 2,470.00 $1,439.63 $— $433.00 $50.00 $0.022 13.25 2.93 3
Refrigeration Cases Auto-closer--reach-in Damaged auto closer,
low-temp
Unit Refrigeration 8 96% 1,297.00 $755.95 $— $300.00 $50.00 $0.022 9.24 2.28 3
Refrigeration Cases Auto-closer--walk-in No or damaged auto closer, med-temp
Unit Refrigeration 8 96% 1,067.00 $621.90 $— $433.00 $40.00 $0.022 9.41 1.35 3
Refrigeration Cases Auto-closer--reach-in Damaged auto closer, med-temp
Unit Refrigeration 8 96% 243.00 $141.63 $— $125.00 $40.00 $0.022 3.00 1.07 3
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 76 Demand-Side Management 2012 Annual Report
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Refrigeration Cases No-heat glass doors Standard low-temp reach-in Unit Refrigeration 12 96% 749.00 $640.64 $— $200.00 $50.00 $0.022 9.25 2.92 3
Refrigeration Cases Anti-sweat heat (ASH) controls Low or med-temp case w/out controls
Linear Foot Refrigeration 8 96% 379.00 $220.90 $— $46.31 $40.00 $0.022 4.39 3.90 6
Vending Machines ENERGY STAR vending machine Standard vending machine
Unit Miscellaneous 14 96% 1,472.00 $1,518.62 $— $350.00 $75.00 $0.022 13.58 3.93 3
Vending Machines Beverage machine control Vending machine with no sensor
Unit Miscellaneous 14 96% 546.50 $563.81 $— $170.00 $75.00 $0.022 6.22 3.04 3
Vending Machines Other cold product control Vending machine with no sensor
Unit Miscellaneous 14 96% 546.50 $563.81 $— $170.00 $50.00 $0.022 8.73 3.05 3
Vending Machines Non-cooled snack control Vending machine with no sensor
Unit Miscellaneous 14 96% 382.55 $394.67 $— $170.00 $25.00 $0.022 11.34 2.19 3
Commercial Kitchen Equipment
ENERGY STAR dishwasher Standard dishwasher Unit Miscellaneous 11 96% 231.00 $191.51 $— $55.00 $15.00 $0.022 9.15 3.14 3
Commercial Kitchen Equipment
Low-temperature dish machine Dish machine w/electric booster
kW Office 13 96% 657.86 $625.61 $— $127.00 $75.00 $0.022 6.71 4.31 3
Commercial Kitchen Equipment
ENERGY STAR refrigerator Standard refrigerator Refrigerator Miscellaneous 13 96% 85.71 $82.79 $— $34.05 $30.00 $0.022 2.49 2.22 3
Commercial Kitchen Equipment
ENERGY STAR 2.0 solid or glass door refrigerator - Less than 30 ft3
Solid or glass door refrigerator— Less than 30 ft3.
Refrigerator Refrigeration 12 96% 4.25 $3.64 $— $74.09 $75.00 $0.022 0.05 0.05 7, 8
Commercial Kitchen Equipment
ENERGY STAR 2.0 solid or glass door refrigerator —-30 to 49.9 ft3
Solid or glass door refrigerator— 30 to 49.9 ft3
Refrigerator Refrigeration 12 96% 5.50 $4.70 $— $91.46 $90.00 $0.022 0.05 0.05 7, 8
Commercial
Kitchen Equipment
ENERGY STAR
2.0 solid or glass door freezer—15 to 29.9 ft3
Solid or glass
door freezer—15 to 29.9 ft3
Freezer Refrigeration 12 96% 27.50 $23.52 $— $162.66 $150.00 $0.022 0.15 0.14 8, 9
Commercial Kitchen Equipment
ENERGY STAR 2.0 solid or glass door freezer—30 to 49.9 ft3
Solid or glass door freezer—30 to 49.9 ft3
Freezer Refrigeration 12 96% 75.00 $64.15 $— $162.66 $175.00 $0.022 0.35 0.37 8, 9
Commercial Kitchen Equipment
Ice maker, up to 200 lbs/day Standard ice maker of the same size
Unit Miscellaneous 10 96% 161.20 $122.48 $— $- $100.00 $0.022 1.14 1.14 10
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 77
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Commercial Kitchen Equipment
Ice maker, more than 200 lbs/day Standard ice maker of the same size
Unit Miscellaneous 10 96% 596.33 $453.10 $— $- $200.00 $0.022 2.04 2.04 11
Evaporator Fans Evaporator fan controls Med-temp walk-in with no controls
Unit Refrigeration 5 96% 361.00 $131.83 $— $85.00 $25.00 $0.022 3.84 1.40 3
Evaporator Fans Efficient evaporator fan motors
Med- or low-temp walk-in Motor Refrigeration 10 96% 478.30 $345.28 $— $161.00 $100.00 $0.022 3.00 1.96 3
Evaporator Fans ECM case fan motors Standard, shaded-pole fan motors
Motor Refrigeration 15 96% 477.00 $498.55 $— $97.25 $60.00 $0.022 6.79 4.50 12
Compressors/Condensers Efficient, low-temp compressor Standard low-temp compressor
Ton Refrigeration 15 96% 1,051.00 $1,098.48 $— $132.00 $45.00 $0.022 15.48 6.95 3
Compressors/Condensers Efficient,
air-cooled condenser
Standard air
cooled condenser
Ton Refrigeration 15 96% 410.01 $428.54 $— $140.30 $100.00 $0.022 3.77 2.79 3
Compressors/Condensers Efficient, water-cooled condenser
Standard air cooled condenser
Ton Refrigeration 15 96% 559.03 $584.28 $— $209.00 $100.00 $0.022 4.99 2.59 3
Compressors/Condensers Efficient, evaporative, condenser
Standard air cooled condenser
Ton Refrigeration 15 96% 678.74 $709.40 $— $278.00 $200.00 $0.022 3.17 2.35 3
Head/Suction Pressure Floating head pressure controller
Standard head pressure control
HP Refrigeration 15 96% 692.50 $723.78 $— $267.58 $60.00 $0.022 9.24 2.53 13
Head/Suction Pressure Floating suction pressure Standard suction pressure control
HP Refrigeration 16 96% 272.91 $301.40 $— $52.48 $10.00 $0.022 18.08 5.10 3
Case/Walk-in Lighting T8 fluorescent lighting T12 or T10 fluorescent lighting
Lamp Refrigeration 6 96% 309.31 $135.78 $— $44.70 $15.00 $0.022 5.98 2.59 3
Case/Walk-in Lighting LED display case lighting T12 or T10 fluorescent lighting
Linear Foot Refrigeration 8 96% 111.25 $64.84 $— $43.00 $15.00 $0.022 3.57 1.40 14
Case/Walk-in
Lighting
Fluorescent
walk-in light fixture
Incandescent
walk-in light fixture
Fixture Refrigeration 6 96% 627.99 $275.68 $— $47.49 $25.00 $0.022 6.82 4.38 3
Office Equipment 80 Plus® PC-desktop Standard personal computer
Unit Office 4 96% 542.32 $163.79 $— $15.00 $5.00 $0.022 9.29 5.93 3
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 78 Demand-Side Management 2012 Annual Report
Measure Name Measure Description Replacing Measure Unit End Use Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Office Equipment 80 Plus PC-server Standard personal computer, server
Unit Office 4 96% 542.32 $163.79 $— $15.00 $10.00 $0.022 7.17 5.88 3
Office Equipment ENERGY STAR PC Standard personal computer
Unit Office 4 96% 457.32 $138.12 $— $10.00 $10.00 $0.022 6.61 6.61 3
Office Equipment ENERGY STAR Copier Standard copier w/o idle/off
Unit Office 6 96% 205.40 $93.68 $— $40.00 $25.00 $0.022 3.05 2.05 3
Office Equipment PC network power management No central control Unit Office 4 96% 99.00 $29.90 $— $13.89 $10.00 $0.022 2.36 1.80 15
Laundry Machines High-efficiency washer Standard washer, electric hot water
Washer Miscellaneous 14 96% 287.00 $296.09 $— $195.00 $25.00 $0.022 9.16 1.46 3
Laundry
Machines
High-efficiency,
coin-op washer
Coin-op
washer, electric hot water
Washer Miscellaneous 8 96% 828.00 $509.13 $— $428.35 $200.00 $0.022 2.24 1.12 3
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Evergreen Consulting Group, LLC. Idaho Power Lighting Tool. 2012. 2 Savings and participant costs calculated from Idaho Power engineering estimates and research. Participant costs include total install cost of the measure. 3 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009. 4 Saving values identified by ADM Associates as needing further review. Will be updated in 2013. 5 Removed from the program in 2012. 6 RTF. ComGroceryAntiSweatHeaters_v1_0.xlsm. 2012. 7 RTF. ComRefrigerator_v3.xlsm. Average solid and glass door. 2012. 8 Measure not cost-effective. Will review in 2013. 9 RTF. ComFreezer_v3.xlsm. Averaged solid and glass door. 2012. 10 RTF. ComIceMaker_v1_1.xlsx. Average of all Energy Star ® air-cooled models producing less than 200 lbs/day. 11 RTF. ComIceMaker_v1_1.xlsx. Average of all Energy Star ® air cooled models producing between 200-1000 lbs/day. 12 RTF. ComGroceryDisplayECMs_v2_2.xlsm. 2012. 13 RTF. ComGroceryFHPCSingleCompressor_v1_1.xls. 2012. Averaged the measures for condensing unit and remote condenser low and medium temperature. 14 RTF. ComGroceryDisplayCaseLEDs_v2_2 and GroceryOpenDisplayCaseLEDs_v1.xls. Averaged the measures for less than 4 W/ln ft and 4-8.5 W/ln ft. 15 RTF. NonResNetCompPwrMgt_v3_0.xlsm. 2011.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 79
Irrigation Efficiency
Segment: Irrigation
2012 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ...................................................... $ 329,372 Test Benefit Cost Ratio
Menu $ 828,508 Utility Cost Test ................................... $ 9,449,350 $ 2,373,201 3.98
Program Incentives ..... Custom 1,215,321 2,043,829 I Total Resource Cost Test ................... 15,660,158 9,522,684 1.64
Total Utility Cost ................................................................. $ 2,373,201 P Ratepayer Impact Measure Test ......... 9,449,350 6,324,272 1.49
Measure Equipment and Installation ..... Menu $ 1,751,486 Participant Cost Test ........................... 14,766,360 11,268,814 1.31
(Incremental Participant Cost) Custom 9,517,328
$ 11,268,814 M
Net Benefit Inputs Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ............................ = Menu S + (Custom S * NTG) = P
2012 Annual Gross Energy (kWh) (Menu) ..... 7,044,889 Total Resource Cost Test ............. = Menu S + (Custom S * NTG) + (NEB * NTG) = P + (Menu M - I) + ((Custom M - I) * NTG)
NPV Cumulative Energy (kWh) ..................... 51,571,167 $ 5,930,957 Ratepayer Impact Measure Test .. = Menu S + (Custom S * NTG) = P + Menu B + (Custom B * NTG)
2012 Annual Gross Energy (kWh) (Custom) . 5,572,275 Participant Cost Test .................... = B + I + NEB = M
NPV Cumulative Energy (kWh) ..................... 40,791,093 4,691,191
Total Electric Savings .................................... $ 10,622,148 S

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings............. Menu $ 2,479,920 Discount Rate .......................................................................................
Custom 1,961,535 Nominal (Weighted Average Cost of Capital [WACC] ........................ 7.00%
Total Participant Bill Savings ............................ 4,441,455 B Real ((1 + WACC) / (1 + Escalation)) - 1 ............................................ 3.88%
Other Benefits Escalation Rate ..................................................................................... 3.00%
Non-Energy Benefits ..................................... Menu $ 2,018,283 Net-to-Gross (NTG)—Custom option only and NEB .............................. 75.00%
Custom 6,262,793 Average 2012 Customer Segment Rate/kWh ........................................ $0.051
Total Non-Energy Benefits ................................................ 8,281,077 NEB Line Losses ........................................................................................... 10.90%

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 for motors between 25 to 5,000 hp. Agricultural motor rewinds are paid under Irrigation Efficiency. Did not pay any incentives for motors greater than 600 hp in 2012.
No NTG. Deemed savings from the Regional Technical Forum (RTF) already accounts for net realized energy savings.
Non-energy benefits based on Idaho Power engineering estimates of annual yield benefit and labor, maintenance, and water savings for Custom and Menu projects.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 80 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Irrigation Efficiency Rewards Market Segment: Irrigation Program Type: Energy Efficiency

Measure Namea Measure Description Replacing Measure Unit End Use Measure Life (yrs)b NTGc
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit
Gross Incremental Participant Costf Incentive/ Unit
Admin Cost ($/kWh)g UC Ratioh TRC Ratioi 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 Irrigation 4 100% 30.00 $12.10 $— $6.56 $1.50 $0.026 5.31 1.65 1
Nozzle Replacement New nozzles
replacing existing worn nozzles of same flow rate or less
Worn nozzle
of same flow rate or less
Unit Irrigation 4.5 100% 39.00 $15.73 $— $1.85 $0.25 $0.026 12.44 5.50 1
Sprinklers Rebuilt or new brass impact sprinklers Unit Irrigation 5 100% 30.00 $15.13 $— $14.27 $2.75 $0.026 4.29 1.00 1
Levelers Rebuilt or new wheel line levelers Unit Irrigation 5 100% 2.00 $1.01 $— $3.76 $0.75 $0.026 1.26 0.26 1, 2
Levelers Rebuilt wheel line levelers Unit Irrigation 5 100% 2.00 $1.01 $— $0.93 $0.75 $0.026 1.26 1.03 1, 3
Sprinklers New rotating-type sprinklers or low-pressure pivot sprinkler heads with the same flow rate or less
Worn sprinkler with the same flow rate or less
Unit Irrigation 5 100% 28.00 $14.12 $— $13.75 $2.75 $0.026 4.06 0.98 1, 4
Regulator Replacement New low pressure regulators Unit Irrigation 5 100% 38.00 $19.16 $— $7.10 $5.00 $0.026 3.20 2.37 1
Gasket Replacement New drains, risercaps, and
gaskets for hand lines, wheel lines or portable mainline
Unit Irrigation 5 100% 24.00 $12.10 $— $10.18 $1.00 $0.026 7.45 1.12 1
Hub Replacement New wheel line hubs Unit Irrigation 10 100% 69.00 $66.72 $— $57.89 $12.00 $0.026 4.84 1.12 1
New Goose Necks New goose neck with drop tube or boomback
Outlet Irrigation 10 100% 14.00 $13.54 $— $12.35 $1.00 $0.026 9.92 1.06 1
Pipe Repair Cut and pipe press or weld repair of leaking hand lines, wheel lines, and portable mainline
Joint Irrigation 8 100% 48.00 $37.93 $— $20.84 $8.00 $0.026 4.10 1.72 1
Gasket Replacement New center pivot base boot gasket Unit Irrigation 8 100% 1,282.00 $1,013.02 $— $289.43 $125.00 $0.026 6.40 3.14 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.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 81
c No Net-to-Gross (NTG) percentage. Deemed savings from the RTF includes realization rate.
d Estimated kWh savings measured at the customer’s meter, excluding line losses.
e Sum of net present value (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 2011 IRP.
f Incremental participant cost prior to customer incentives.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives). i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. IrrgAgSprinklerNozzleFY10v2_1.xls. Western Idaho. 2010. 2 Measure not cost-effective. Measure updated in 2012 to remove new wheel line levelers. 3 Average costs from customer applications. 4 Measure not cost-effective. Will be reviewed in 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 82 Demand-Side Management 2012 Annual Report
Year: 2012 Program: Irrigation Efficiency Rewards Market Segment: Irrigation Program Type: Energy Efficiency

Measure Name Measure Description Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind: Motor size 25 hp
Green Motors Program Rewind: Motor size 25 hp
Standard rewind practice
Motor Irrigation 20 80% 237.00 $401.77 $— $204.14 $50.00 $0.050 5.20 1.74 1
Green Motors Program Rewind: Motor size 30 hp
Green Motors Program Rewind: Motor size 30 hp
Standard rewind practice
Motor Irrigation 20 80% 254.00 $430.59 $— $224.21 $60.00 $0.050 4.74 1.69 1
Green Motors
Program Rewind: Motor size 40 hp
Green Motors
Program Rewind: Motor size 40 hp
Standard
rewind practice
Motor Irrigation 20 80% 297.00 $503.48 $— $273.99 $80.00 $0.050 4.25 1.61 1
Green Motors Program Rewind: Motor size 50 hp
Green Motors Program Rewind: Motor size 50 hp
Standard rewind practice
Motor Irrigation 20 80% 322.00 $545.86 $— $303.32 $100.00 $0.050 3.76 1.57 1
Green Motors Program Rewind: Motor size 60 hp
Green Motors Program Rewind: Motor size 60 hp
Standard rewind practice
Motor Irrigation 20 80% 328.00 $556.04 $— $357.73 $120.00 $0.050 3.26 1.36 1
Green Motors Program Rewind: Motor size 70 hp
Green Motors Program Rewind: Motor size 70 hp
Standard rewind practice
Motor Irrigation 20 80% 341.00 $578.07 $— $386.67 $150.00 $0.050 2.77 1.30 1
Green Motors Program Rewind: Motor size 100 hp
Green Motors Program Rewind: Motor size 100 hp
Standard rewind practice
Motor Irrigation 20 80% 585.00 $991.71 $— $479.67 $200.00 $0.050 3.46 1.75 1
Green Motors Program Rewind: Motor size 125 hp
Green Motors Program Rewind: Motor size 125 hp
Standard rewind practice
Motor Irrigation 20 80% 727.00 $1,232.43 $— $538.71 $250.00 $0.050 3.44 1.91 1
Green Motors Program Rewind: Motor size 150 hp
Green Motors Program Rewind: Motor size 150 hp
Standard rewind practice
Motor Irrigation 20 80% 867.00 $1,469.76 $— $600.07 $300.00 $0.050 3.42 2.02 1
Green Motors
Program Rewind: Motor size 200 hp
Green Motors
Program Rewind: Motor size 200 hp
Standard
rewind practice
Motor Irrigation 20 80% 1,149.00 $1,947.82 $— $722.40 $400.00 $0.050 3.41 2.18 1
Green Motors Program Rewind: Motor size 250 hp
Green Motors Program Rewind: Motor size 250 hp
Standard rewind practice
Motor Irrigation 20 80% 1,434.00 $2,430.96 $— $928.48 $500.00 $0.050 3.40 2.13 1
Green Motors Program Rewind: Motor size 300 hp
Green Motors Program Rewind: Motor size 300 hp
Standard rewind practice
Motor Irrigation 20 80% 1,718.00 $2,912.41 $— $938.51 $600.00 $0.050 3.40 2.44 1
Green Motors Program Rewind: Motor size 350 hp
Green Motors Program Rewind: Motor size 350 hp
Standard rewind practice
Motor Irrigation 20 80% 2,005.00 $3,398.94 $— $983.66 $700.00 $0.050 3.40 2.65 1
Green Motors Program Rewind: Motor size 400 hp
Green Motors Program Rewind: Motor size 400 hp
Standard rewind practice
Motor Irrigation 20 80% 2,285.00 $3,873.60 $— $1,098.66 $800.00 $0.050 3.39 2.69 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2012 Annual Report Page 83
Measure Name Measure Description Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Benefit Cost Benefit/Cost Tests
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit
Gross Incremental Participant Coste Incentive/ Unit
Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind: Motor size 450 hp
Green Motors Program Rewind: Motor size 450 hp
Standard rewind practice
Motor Irrigation 20 80% 2,563.00 $4,344.87 $— $1,200.92 $900.00 $0.050 3.38 2.74 1
Green Motors Program Rewind: Motor size 500 hp
Green Motors Program Rewind: Motor size 500 hp
Standard rewind practice
Motor Irrigation 20 80% 2,848.00 $4,828.02 $— $1,297.40 $1,000.00 $0.050 3.38 2.80 1
Green Motors Program Rewind: Motor size 600 hp
Green Motors Program Rewind: Motor size 600 hp
Standard rewind practice
Motor Irrigation 20 80% 3,418.00 $5,794.30 $— $1,911.88 $1,200.00 $0.050 3.38 2.39 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc. 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses. d Sum of net present value (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 2011 IRP.
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2012 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. AgMotorsRewind_v1_3.xlsm. 2012.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 84 Demand-Side Management 2012 Annual Report
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