20120316DSM 2011 Supplement 1.PDF

Demand-Side Management
2011 Annual Report
March 15, 2012
Supplement 1:
Cost-Effectiveness
Photo Captions
Top Photo:
Courtesy of the Idaho Central Credit Union
The Idaho Central Credit Union’s corporate office in Chubbuck, Idaho incorporates numerous energy efficient measures provided through Idaho Power’s Building Efficiency program.
Middle Photo:
Idaho Power offers an energy efficiency program and a demand-response program for irrigation customers.
Bottom Photo:
Idaho Power offers numerous energy efficient programs for residential customers.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 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 .....................................................................................................................................3
Results ..............................................................................................................................................4
2011 DSM Detailed Expense by Program .............................................................................................6
Cost-Effectiveness Tables by Program ......................................................................................................11
A/C Cool Credit .............................................................................................................................11
FlexPeak Management ...................................................................................................................13
Irrigation Peak Rewards .................................................................................................................15
Ductless Heat Pump Pilot ..............................................................................................................17
Energy Efficient Lighting ..............................................................................................................19
Energy House Calls........................................................................................................................21
ENERGY STAR® Homes Northwest ............................................................................................25
Heating & Cooling Efficiency Program ........................................................................................31
Home Improvement Program ........................................................................................................37
Home Products Program ................................................................................................................67
Rebate Advantage ..........................................................................................................................73
See ya later, refrigerator® ...............................................................................................................77
Weatherization Assistance for Qualified Customers .....................................................................79
Weatherization Solutions for Eligible Customers..........................................................................81
Building Efficiency ........................................................................................................................85
Custom Efficiency .........................................................................................................................89
Easy Upgrades ...............................................................................................................................97
Irrigation Efficiency .....................................................................................................................115

Supplement 1: Cost-Effectiveness Idaho Power Company
Page ii Demand-Side Management 2011 Annual Report
LIST OF TABLES
Table 1. 2011 non-cost-effective measures ........................................................................................5
Table 2. 2011 DSM detailed expenses by program (dollars) .............................................................6
Table 3. Cost-effectiveness summary by program...........................................................................10

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 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. In the past, most of Idaho Power’s
energy efficiency and demand response programs were preliminarily identified through the Integrated
Resource Plan (IRP) process. Because of Idaho Power’s diversified portfolio of programs, in the 2011 IRP most of the new potential for energy efficiency in Idaho Power’s service area is based on additional measures to be added to programs rather than new programs. The process in the IRP remains
the same for determining if measures should be adopted as it was 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 in order 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 help 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 such as ADM Associates, Inc.,
and Portland Energy Conservation, Inc. (PECI) for program assumptions.
Idaho Power’s goal is to have all mature programs have benefit/cost (B/C) ratios greater than 1.0 for the total resource cost (TRC) test, utility cost (UC) test, and participant cost test (PCT) at the program level
and the measure level where appropriate. An exception to the measure level cost-effectiveness is when
there is 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 reexamined
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, and 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. Traditionally, Idaho Power 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.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 2 Demand-Side Management 2011 Annual Report
These tests are still used because, as defined in the TAG and California Standard Practice Manual,
they are the 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 on a one-year perspective. The annual energy savings benefit value is summed over the life of the measure or program
and are discounted to reflect today’s dollars. The result of the one-year perspective is shown in
Supplement 1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2011 Annual
Report illustrates the program cost-effectiveness to date by including the culmination of actual historic
savings value and expenses as well as the on-going 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 in which
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.
In 2011, Idaho Power reviewed its methodology to analyze the cost-effectiveness of its demand response programs. In September, the company contracted with Freeman, Sullivan & Co. (FSC Group) to conduct
a two-day workshop on demand response. At the workshop, FSC Group recommended the application of
an effective load carrying capacity (ELCC) to reduce the avoided capacity cost benefit. Because demand
response programs cannot perfectly match the reliability of a generation resource due to the programs’
limited availability, it should not claim the full avoided capacity cost benefit of that supply-side resource. To determine the ELCC for demand response programs, Idaho Power created 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 7 percent of the total hours were outside the programs’ parameters when analyzed as they would be dispatched. 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.
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 2011 Annual Report Supplement 1: Cost-Effectiveness, savings, costs, and load shapes were derived from the Demand-Side
Management Potential Study conducted by Nexant, Inc., in 2009. Another source of information is the
Regional Technical Forum (RTF). The RTF, which meets 10-12 times annually, 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 Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 3
Idaho Power staff participates in the RTF by attending the monthly meetings and contributing to
various sub-committees.
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, 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, it was determined
that the WACC was not an appropriate discount rate to use. Because the customer bill savings is based
on Idaho Power’s 2011 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 ELCC of 93.4 percent, the annual avoided capacity cost is $87.80/kW.
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.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 4 Demand-Side Management 2011 Annual Report
For most programs and individual measures, the NTG ratios are derived from Demand-Side
Management Potential Study or the California Public Utilities Commission (CPUC) DEER. The NTG
adjustment is shown as part of the 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 which take into account a NTG 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 adjustment of 69 percent, the standard custom program NTG from DEER1
Results

which includes a spillover adjustment, is used to calculate the cost-effectiveness of this program.
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, 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 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 on-going participant costs.
The Demand-Side Management 2011 Annual Report contains program UC and TRC B/C ratios using
actual cost information over the life of the program through 2011. Supplement 1: Cost-Effectiveness contains annual cost-effectiveness metrics for each program using actual information from 2011, 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 on Table 3.
In 2011, all but one of Idaho Powers energy efficiency programs were cost-effective from the UC, TRC,
and PCT perspective. Home Improvement Program had a TRC of 0.76 due to the lower than anticipated
cooling savings for gas heated homes. At Idaho Power’s request, the RTF made additional runs of the
residential weatherization model with central air conditioning assumptions for all Idaho specific climate zones. That analysis was received in October 2011, approved by the RTF in November 2011, and is posted as a supporting file at the RTF website at
http://www.nwcouncil.org/energy/rtf/measures/support/Default.asp. When the new savings from this

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 2011 Annual Report Page 5
analysis was applied in the cost-effectiveness calculations for the Home Improvement Program,
the program became not cost-effective for 2011.
All of the demand response programs were determined to be cost-effective from the long term
prospective. To be consistent with the IRP, and since demand response programs are inherently different from energy efficiency programs, 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 10 years. However, Idaho Power does calculate the B/C ratios for each demand response program
on an individual year basis. Based on the results of the impact evaluation conducted by ADM
Associates, Inc., the A/C Cool Credit program was determined to not be cost-effective for 2011. For 2011, FlexPeak Management and Irrigation Peak Rewards programs passed the B/C tests with TRCs
of 1.93 and 2.32 respectively, while the A/C Cool Credit program had a TRC B/C ratio of 0.74.
Fifty-one measures within programs were not cost-effective from the UC or TRC perspective. Of those
51 measures, five were measures that were removed from the program offerings in 2011 but were
carried over from 2010. Six measures will be reviewed and possibly modified in 2012. Three measures are bundled with other cost-effective measures and analyzed at a project level. Thirty-seven measures
will be removed in 2012.
Table 1. 2011 non-cost-effective measures
Program
Number of
Measures Notes
Easy Upgrades 4 These are measures from the program’s 2010 offering that carried over into 2011. They were removed from the program in early 2011.
Home Improvement Program 37 Thirty-four measures are for varying insulation levels for non-electrically heated homes. These will be removed from the program after April 1, 2012. Three measures are for electrically
heated homes with an average system or heat pump for lower R-value increases. These will be reviewed for non-electric benefits.
Home Products Program 5 Three measures will be removed from the program after March 1,
2012. Two measures will be reviewed in 2012 for other non-electric benefits, such as gas and water savings.
Irrigation Efficiency Rewards 1 This measure will be revised in 2012 to remove the high-cost item
that brought down cost-effectiveness. Non-electric benefits are not allocated by measures but will be researched in 2012.
Weatherization Solutions for Eligible
Customers
3 These measures are not cost-effective due to high administration
costs, which are calculated on a dollar-per-kWh-saved basis. These Measures are bundled with other cost-effective measures and cost-effectiveness is analyzed on a per-project basis.
Holiday Lighting 1 Holiday Lighting program was discontinued in 2011. Residual 2010 applications processed in early 2011.
Total 51

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 that are not analyzed at the
measure level include Custom Efficiency, the Custom Option of Irrigation Efficiency Rewards,
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 6 Demand-Side Management 2011 Annual Report
and Weatherization Assistance for Qualified Customers where projects include multiple interactive
measures that are analyzed at the project level.
The measure level cost-effectiveness includes inputs of measure life, energy savings, demand reduction,
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.
2011 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 2011 Annual Report. These expenses are broken out by major expense type
(incentives, labor/administration, materials, other expenses, and purchased services).
Table 2. 2011 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 ................................................................................ $ 2,781,553 $ 114,989 $ 0 $ 2,896,542
Customer Incentives ...................................................................... 758,151 9,214 0 767,365
Labor/Administration Expense ....................................................... 83,851 4,407 0 88,258
Materials & Equipment .................................................................. 794,441 42,303 0 836,744
Other Expense .............................................................................. 307,172 14,995 0 322,167
Purchased Services ...................................................................... 837,938 44,070 0 882,008
Ductless Heat Pump Pilot................................................................ 183,260 7,923 0 191,183
Customer Incentives ...................................................................... 108,750 4,000 0 112,750
Labor/Administration Expense ....................................................... 32,852 1,730 0 34,582
Materials & Equipment .................................................................. 20 1 0 21
Other Expense .............................................................................. 24,147 1,271 0 25,418
Purchased Services ...................................................................... 17,491 921 0 18,412
Energy Efficient Lighting................................................................. 1,668,328 50,805 0 1,719,133
Customer Incentives ...................................................................... 1,358,588 39,647 0 1,398,235
Labor/Administration Expense ....................................................... 58,442 3,082 0 61,524
Materials & Equipment .................................................................. 105 6 0 111
Other Expense .............................................................................. 4,005 83 0 4,088
Purchased Services ...................................................................... 247,188 7,987 0 255,175
Energy House Calls ......................................................................... 447,229 36,146 0 483,375
Labor/Administration Expense ....................................................... 44,972 2,367 0 47,339
Materials & Equipment .................................................................. 4 0 0 4
Other Expense .............................................................................. 54,799 2,884 0 57,683
Purchased Services ...................................................................... 347,454 30,895 0 378,349
ENERGY STAR® Homes .................................................................. 255,405 4,357 0 259,762
Customer Incentives ...................................................................... 172,600 0 0 172,600
Labor/Administration Expense ....................................................... 51,169 2,691 0 53,860
Materials & Equipment .................................................................. 2,423 128 0 2,551
Other Expense .............................................................................. 29,213 1,538 0 30,751
Heating & Cooling Efficiency Program ........................................... 188,876 6,894 0 195,770
Customer Incentives ...................................................................... 57,400 650 0 58,050

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 7
Table 2. 2011 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Labor/Administration Expense ....................................................... $ 47,785 $ 2,518 $ 0 $ 50,303
Other Expense .............................................................................. 35,279 1,857 0 37,136
Purchased Services ...................................................................... 48,412 1,869 0 50,281
Home Improvement Program .......................................................... 666,041 0 0 $666,041
Customer Incentives ...................................................................... 486,873 0 0 486,873
Labor/Administration Expense ....................................................... 73,137 0 0 73,137
Other Expense .............................................................................. 64,511 0 0 64,511
Purchased Services ...................................................................... 41,520 0 0 41,520
Home Products Program ................................................................. 619,764 18,559 0 638,323
Customer Incentives ...................................................................... 475,351 10,967 0 486,318
Labor/Administration Expense ....................................................... 59,899 3,153 0 63,052
Materials & Equipment .................................................................. 11 1 0 12
Other Expense .............................................................................. 37,167 1,956 0 39,123
Purchased Services ...................................................................... 47,336 2,482 0 49,818
Oregon Residential Weatherization ................................................ 0 6,690 1,236 7,926
Customer Incentives ...................................................................... 0 3,205 0 3,205
Labor/Administration Expense ....................................................... 0 3,485 1,236 4,721
Rebate Advantage ........................................................................... 59,241 4,228 0 63,469
Customer Incentives ...................................................................... 11,000 1,500 0 12,500
Labor/Administration Expense ....................................................... 14,447 760 0 15,207
Other Expense .............................................................................. 31,694 1,668 0 33,362
Purchased Services ...................................................................... 2,100 300 0 2,400
See ya later, refrigerator® ................................................................ 634,967 19,426 0 654,393
Customer Incentives ...................................................................... 95,460 2,610 0 98,070
Labor/Administration Expense ....................................................... 47,575 2,487 0 50,062
Other Expense .............................................................................. 59,747 3,145 0 62,892
Purchased Services ...................................................................... 432,185 11,184 0 443,369
Weatherization Assistance for Qualified Customers ..................... 0 0 1,324,415 1,324,415
Labor/Administration Expense ....................................................... 0 0 49,031 49,031
Other Expense .............................................................................. 0 0 552 552
Purchased Services ...................................................................... 0 0 1,274,832 1,274,832
Weatherization Solutions for Eligible Customersa ........................ 774,254 (2,306) 16,200 788,148
Labor/Administration Expense ....................................................... 6,222 0 16,200 22,422
Other Expense .............................................................................. 806 0 0 806
Purchased Servicesa ..................................................................... 767,226 (2,306) 0 764,920
Commercial/Industrial
Building Efficiency .......................................................................... 1,277,422 14,003 0 1,291,425
Customer Incentives ...................................................................... 1,010,086 0 0 1,010,086
Labor/Administration Expense ....................................................... 135,187 7,114 0 142,301
Other Expense .............................................................................. 18,544 910 0 19,454
Purchased Services ...................................................................... 113,605 5,979 0 119,584
Comprehensive Lighting ................................................................. 2,404 0 0 2,404
Labor/Administration Expense ....................................................... 2,303 0 0 2,303
Other Expense .............................................................................. 101 0 0 101
Easy Upgrades ................................................................................. 4,598,019 121,447 0 4,719,466
Customer Incentives ...................................................................... 3,823,896 80,696 0 3,904,592
Labor/Administration Expense ....................................................... 385,429 20,291 0 405,720
Materials & Equipment .................................................................. 146 8 0 154

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 8 Demand-Side Management 2011 Annual Report
Table 2. 2011 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Other Expense .............................................................................. $ 29,755 $ 1,566 $ 0 $ 31,321
Purchased Services ...................................................................... 358,793 18,886 0 377,679
FlexPeak Management .................................................................... 1,954,850 102,880 0 2,057,730
Customer Incentives ...................................................................... 1,895,034 99,739 0 1,994,773
Labor/Administration Expense ....................................................... 54,915 2,884 0 57,799
Other Expense .............................................................................. 13 0 0 13
Purchased Services ...................................................................... 4,888 257 0 5,145
Holiday Lighting ............................................................................... 2,568 0 0 2,568
Customer Incentives ...................................................................... 2,568 0 0 2,568
Oregon Commercial Audits ............................................................. 0 13,597 0 13,597
Labor/Administration Expense ....................................................... 0 7,299 0 7,299
Other Expense .............................................................................. 0 973 0 973
Purchased Services ...................................................................... 0 5,325 0 5,325
Custom Efficiency ........................................................................... 413,959 1,385,613 6,984,239 8,783,811
Customer Incentivesb .................................................................... (526,661) 1,272,003 6,984,239 7,729,581
Labor/Administration Expense ....................................................... 428,670 22,550 0 451,220
Other Expense .............................................................................. 81,001 3,826 0 84,827
Purchased Services ...................................................................... 430,949 87,234 0 518,183
Irrigation
Irrigation Efficiency Rewards ......................................................... 2,153,613 176,619 30,072 2,360,304
Customer Incentives ...................................................................... 1,900,731 163,372 0 2,064,103
Labor/Administration Expense ....................................................... 234,805 12,353 30,072 277,230
Materials & Equipment .................................................................. 393 21 0 414
Other Expense .............................................................................. 16,102 848 0 16,950
Purchased Services ...................................................................... 1,582 25 0 1,607
Irrigation Peak Rewards .................................................................. 11,790,216 254,013 41,993 12,086,222
Customer Incentives ...................................................................... 10,127,328 236,715 0 10,364,043
Labor/Administration Expense ....................................................... 55,720 2,932 41,993 100,645
Materials & Equipment .................................................................. 937 49 0 986
Other Expense .............................................................................. 32,349 1,703 0 34,052
Purchased Services ...................................................................... 1,573,882 12,614 0 1,586,496
Energy Efficiency Total ....................................................................... 30,471,969 2,335,883 8,398,155 41,206,007
Market Transformation
NEEAc ............................................................................................... 2,952,973 155,420 0 3,108,393
Purchased Services ...................................................................... 2,952,973 155,420 0 3,108,393
Market Transformation Total .............................................................. 2,952,973 155,420 0 3,108,393
Other Programs and Activities
Residential
Residential Economizer .................................................................. 101,612 101 0 101,713
Labor/Administration Expense ....................................................... 24,595 0 0 24,595
Materials & Equipment .................................................................. 1,920 101 0 2,021
Other Expense .............................................................................. 1,272 0 0 1,272
Purchased Services ...................................................................... 73,825 0 0 73,825
Residential Energy Efficiency Education Initiative ....................... 151,791 7,854 0 159,645
Labor/Administration Expense ....................................................... 96,709 5,089 0 101,798
Materials & Equipment .................................................................. 1,730 91 0 1,821
Other Expense .............................................................................. 53,352 2,674 0 56,026

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 9
Table 2. 2011 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Commercial
Commercial Education Initiative ..................................................... $ 85,340 $ 4,516 $ 0 $ 89,856
Labor/Administration Expense ....................................................... 72,251 3,827 0 76,078
Materials & Equipment .................................................................. 503 27 0 530
Other Expense .............................................................................. 10,568 556 0 11,124
Purchased Services ...................................................................... 2,018 106 0 2,124
Other
Energy Efficiency Direct Program Overhead ................................. 199,957 10,520 0 210,477
Labor/Administration Expense ....................................................... 84,951 4,472 0 89,423
Other Expense .............................................................................. 81,416 4,280 0 85,696
Purchased Services ...................................................................... 33,590 1,768 0 35,358
Local Energy Efficiency Funds ....................................................... 1,026 0 0 1,026
Customer Incentives ...................................................................... 1,026 0 0 1,026
Other Programs and Activities Total .................................................. 539,726 22,991 0 562,717
Indirect Program Expenses
Residential Overhead ...................................................................... 167,477 8,824 0 176,301
Labor/Administration Expense ....................................................... 134,730 7,069 0 141,799
Other Expense .............................................................................. 4,750 250 0 5,000
Purchased Services ...................................................................... 27,997 1,505 0 29,502
Commercial/Industrial/Irrigation Overhead .................................... 178,255 9,384 0 187,639
Labor/Administration Expense ....................................................... 159,306 8,355 0 167,661
Materials & Equipment .................................................................. 460 24 0 484
Purchased Services ...................................................................... 18,489 1,005 0 19,494
Energy Efficiency Accounting and Analysis ................................. 633,972 33,686 136,212 803,870
Labor/Administration Expense ....................................................... 397,022 20,891 129,162 547,075
Materials & Equipment .................................................................. 21 1 0 22
Other Expense .............................................................................. 16756 882 7,050 24,688
Purchased Services ...................................................................... 220,173 11,912 0 232,085
Energy Efficiency Advisory Group ................................................. 3,206 169 0 3,375
Labor/Administration Expense ....................................................... 2,539 134 0 2,673
Other Expense .............................................................................. 667 35 0 702
Special Accounting Entries ............................................................ 148,962 533 68,455 217,950
Indirect Program Expenses Total ....................................................... 1,131,872 52,596 204,667 1,389,135
Totals.................................................................................................... $ 35,096,540 $ 2,566,890 $ 8,602,822 $ 46,266,252
a Reclassify 2010 Oregon Rider balance of ($2,306) to the Idaho Rider.
b Idaho Rider Custom Efficiency includes reclassification of $526,781 from the Idaho Rider to the Oregon Rider, (4 projects from 2010). Idaho Power balance of
$6,984,239 for Idaho Custom Efficiency incentives, not included in base rates for 2011. (see footnote in Appendix 1). c NEEA Funding addressed in IPUC per Order No. 31080, dated 5/12/10. 2012 annual expense expected at $3.7 million (see footnote in Appendix 1).
d Residential Economizer Oregon Rider balance $101, to be reclassified to Idaho Rider in 2012.
e Special Accounting Entries, Idaho Power accrual amount of $34,146, not included in base rates for 2011.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 10 Demand-Side Management 2011 Annual Report
Table 3. Cost-effectiveness summary by program
2011 Benefit/Cost Tests
Program
Utility Cost
(UC)
Total Resource
Cost (TRC)
Ratepayer Impact
Measure (RIM)
Participant
Cost (PCT)
A/C Cool Credit .......................................................... 1.10 1.10 1.12 N/A
FlexPeak Management ............................................... 1.19 1.19 1.20 N/A
Irrigation Peak Rewards ............................................. 1.72 1.64 1.90 N/A
Ductless Heat Pump Pilot ........................................... 3.09 1.24 1.06 1.22
Energy Efficient Lighting ............................................. 3.99 2.48 0.84 3.21
Energy House Calls .................................................... 2.44 2.44 0.81 N/A
ENERGY STAR ® Homes Northwest ......................... 3.72 1.79 1.01 2.02
Heating & Cooling Efficiency Program ........................ 4.83 1.78 1.20 1.67
Home Improvement Program ...................................... 2.64 0.76 0.97 0.76
Home Products Program ............................................ 2.04 1.06 0.81 1.33
Rebate Advantage ...................................................... 2.90 2.28 0.87 5.79
See ya later, refrigerator® ........................................... 1.52 1.52 0.66 N/A
Weatherization Assistance for Qualified Customers .... 2.67 1.29 0.90 N/A
Weatherization Solutions for Eligible Customers ......... 1.84 1.84 0.78 N/A
Building Efficiency ...................................................... 5.91 2.62 1.41 2.03
Custom Efficiency ....................................................... 4.42 2.37 1.86 1.34
Easy Upgrades ........................................................... 5.44 3.00 1.38 2.44
Irrigation Efficiency ..................................................... 4.71 1.55 1.59 1.24

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 11
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 .............................................. $ 23,904,459 Test Benefit Cost Ratio
Total Program Incentives .................................................... 9,285,774 I Utility Cost Test ................................... $ 37,186,165 $ 33,948,331 1.10
Total Utility Cost ................................................................. $ 33,190,233 P Total Resource Cost Test ................... 37,186,165 33,948,331 1.10
Ratepayer Impact Measure Test ......... 37,186,165 33,190,233 1.12
Total Shifted Energy Utility Cost ........................................... $ 758,098 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) ............................. 17,751,173 $ 1,734,556 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2022 Reduction Capacity (MW)..................... 38 35,451,609 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings .................................... $ 37,186,165 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-Electric Benefits ........................................................ $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response) ................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: 2022 Reduction capacity based on the assumption of 40,000 participants at an average realized load reduction of 0.84 kW (0.95 kW with Summer Peak Line Loss of 13%).

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 12 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 13
FlexPeak Management
Segment: Commercial/Industrial
10-Year Program Cost-Effectiveness Summary
Program Inception: 2009
Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................. $ 581,847 Test Benefit Cost Ratio
Total Program Incentives .................................................... 29,965,837 I Utility Cost Test ................................... $ 36,551,819 $ 30,629,291 1.19
Total Utility Cost ................................................................. $ 30,547,684 P Total Resource Cost Test ................... 36,551,819 30,629,291 1.19
Ratepayer Impact Measure Test ......... 36,551,819 30,547,684 1.20
Total Shifted Energy Utility Cost ........................................... $ 81,607 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) ............................. 22,288,236 $ 1,972,011 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2019 Reduction Capacity (MW)..................... 57 34,579,808 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings .................................... $ 36,551,819 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-Electric Benefits ........................................................ $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response) ................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: 2019 Reduction capacity based on contractual target to achieve 50 MW (57 MW with Summer Peak Line Loss of 13%).
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 14 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 15
Irrigation Peak Rewards
Segment: Irrigation
20-Year Program Cost-Effectiveness Summary
Program Inception: 2009
Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................. $ 16,072,564 Test Benefit Cost Ratio
Total Program Incentives .................................................... 175,950,555 I Utility Cost Test ................................... $ 365,066,962 $ 211,898,973 1.72
Total Utility Cost ................................................................. $ 192,023,119 P Total Resource Cost Test ................... 365,066,962 223,043,414 1.64
Ratepayer Impact Measure Test ......... 365,066,962 192,023,119 1.90
Total Shifted Energy Utility Cost ........................................... $ 19,875,854 SE Participant Cost Test ........................... N/A N/A N/A

Total Measure Equipment and Installation (Incremental Participant Cost) .............................................. $ 11,144,441 M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test ........................................ = S = P + SE
Cumulative Energy (kWh) ......................... 204,887,880 $ 23,473,783 Total Resource Cost Test ......................... = S + NUI + NEB = P + M + SE
2029 Reduction Capacity (MW)................. 326 341,593,179 Ratepayer Impact Measure Test .............. = S = P + B
Total Electric Savings ................................ $ 365,066,962 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-Electric Benefits ........................................................ $ — NEB Effective Load Carrying Capacity (ELCC) .............................................. 93.40%
Summer Peak Line Loss (for Demand Response) ................................. 13.00%
Line Losses ........................................................................................... 10.90%
Notes: Because of the fixed and variable incentive structure, the nature of summer peak loads, and the weather in 2011, the program was not dispatched in 2011.
2029 Reduction capacity based on the assumption that the available capacity will increase slightly in 2012 over 2011 and remain constant until 2029.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 16 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 17
Ductless Heat Pump Pilot
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 78,433 Test Benefit Cost Ratio
Program Incentives ............................................................. 112,750 I Utility Cost Test ................................... $ 591,603 $ 191,183 3.09
Total Utility Cost ................................................................. $ 191,183 P Total Resource Cost Test ................... 591,603 478,263 1.24
Ratepayer Impact Measure Test ......... 591,603 560,521 1.06
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 471,600 M Participant Cost Test ........................... 574,422 471,600 1.22

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 458,500 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 5,961,609 $ 739,504 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 739,504 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 461,672 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 18 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Ductless Heat Pump Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Ductless Heat Pump
High-Efficiency Ductless Split Heat Pump System—Existing Single Family w/ Zonal Electric Heat
Zonal Electric Unit Heating & Cooling
20 80% 3,500.00 $5,285.77 $ — $3,407.11 $750.00 $0.171 3.14 1.22 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 & Cooling
20 80% 3,500.00 $5,285.77 $ — $3,407.11 $750.00 $0.171 3.14 1.22 1
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. DHP_Provisional_Existing_FY10v1_2.xls. 2010.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 19

Energy Efficient Lighting
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 320,898 Test Benefit Cost Ratio
Program Incentives ............................................................. 1,398,235 I Utility Cost Test ................................... $ 6,850,821 $ 1,719,133 3.99
Total Utility Cost ................................................................. $ 1,719,133 P Total Resource Cost Test ................... 6,850,821 2,764,623 2.48
Ratepayer Impact Measure Test ......... 6,850,821 8,168,003 0.84
Measure Equipment and Installation (Incremental Participant Cost) .............................................. $ 2,443,725 M Participant Cost Test ........................... 7,847,105 2,443,725 3.21

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 19,694,381 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 98,478,811 $ 6,850,821 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 6,850,821 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 6,448,870 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) .......................................................................................... 100%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: No NTG. Deemed savings from the Regional Technical Forum (RTF) already accounts for net realized energy savings.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 20 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
CFL Specialty Bulb—Retail 3-way CFL Incandescent bulb Bulb Lighting 7 100% 22.00 $10.19 $ — $5.23 $2.00 $0.016 4.33 1.83 1
CFL Specialty Bulb—Retail Dimmable Incandescent bulb Bulb Lighting 7 100% 23.00 $10.66 $ — $7.22 $2.00 $0.016 4.50 1.40 1
CFL Specialty Bulb—Retail A-lamps Incandescent bulb Bulb Lighting 7 100% 25.00 $11.58 $ — $3.68 $2.00 $0.016 4.83 2.84 1
CFL Specialty
Bulb—Retail
Cold cathode
candelabra
Incandescent
bulb
Bulb Lighting 12 100% 14.50 $11.37 $ — $5.21 $2.00 $0.016 5.09 2.09 1
CFL Specialty Bulb—Retail CFL candelabra Incandescent bulb Bulb Lighting 6 100% 19.00 $7.52 $ — $1.59 $2.00 $0.016 3.26 3.97 1
CFL Specialty Bulb—Retail Daylight CFL Incandescent bulb Bulb Lighting 7 100% 23.00 $10.66 $ — $2.13 $2.00 $0.016 4.50 4.27 1
CFL Specialty Bulb—Retail Dimmable Reflector Incandescent bulb Bulb Lighting 8 100% 26.00 $13.77 $ — $11.92 $2.00 $0.016 5.70 1.12 1
CFL Specialty Bulb—Retail Globe Incandescent bulb Bulb Lighting 6 100% 13.00 $5.15 $ — $1.79 $2.00 $0.016 2.33 2.58 1
CFL Specialty Bulb—Retail Reflector CFL Incandescent bulb Bulb Lighting 8 100% 25.00 $13.24 $ — $0.60 $2.00 $0.016 5.52 13.24 1
CFL Specialty Bulb—Retail T2 twist Incandescent bulb Bulb Lighting 7 100% 25.00 $11.58 $ — $2.22 $2.00 $0.016 4.83 4.42 1
CFL Specialty Bulb—Retail High wattage Incandescent bulb Bulb Lighting 9 100% 38.00 $22.61 $ — $3.36 $2.00 $0.016 8.67 5.70 1
CFL Specialty Bulb—Retail Any specialty bulb Incandescent bulb Bulb Lighting 7 100% 19.00 $8.80 $ — $1.76 $2.00 $0.016 3.82 4.26 1
CFL Spiral Bulb—Retailer
Spiral Bulb Incandescent bulb Bulb Lighting 6 100% 16.00 $6.33 $ — $2.75 $1.45 $0.016 3.71 2.11 2
a Average measure life.
b No NTG percentage. Deemed savings from RTF includes realization rate. c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. ResSpecialtyLighting_v1_1.xlsm. Residential lighting. Any location. 2011.
2 RTF. ResCFLLighting_v2_1.xlsm. Any Interior or Exterior Application. 2011.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 21
Energy House Calls
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 483,375 Test Benefit Cost Ratio
Program Incentives ............................................................. — I Utility Cost Test ................................... $ 1,473,747 $ 483,375 2.44
Total Utility Cost ................................................................. $ 483,375 P Total Resource Cost Test ................... 1,473,747 483,375 2.44
Ratepayer Impact Measure Test ......... 1,473,747 1,705,779 0.81
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ — M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 1,214,004 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 15,742,485 $ 1,473,747 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 1,473,747 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ N/A N/A
NPV Cumulative Participant Savings............. $ 1,222,404 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: Increased deemed savings from the RTF and lower administration costs increased program cost-effectiveness over 2010. No participant cost.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 22 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 1 (average heating system)
Pre-existing duct leakage Home Heating 20 80% 1,082.00 $1,229.57 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 1 (electric FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 20 80% 1,223.00 $1,389.80 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 1 (electric FAF heating system w/o CAC)
Pre-existing duct leakage Home Heating 20 80% 1,177.00 $1,337.52 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct
tightness—PTCS duct sealing—heating zone 1 (electric heat pump heating system)
Pre-existing duct leakage Home Heating 20 80% 708.00 $804.56 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct
tightness—PTCS duct sealing—heating zone 2 (average heating system)
Pre-existing duct leakage Home Heating 20 80% 1,806.00 $2,052.31 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 2 (electric
FAF heating system w/CAC)
Pre-existing duct leakage Home Heating 20 80% 1,984.00 $2,254.58 $ – $ – $ – $0.398 2.28 2.28 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 23

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure Life (years)a NTGb
Annual Gross Energy Savings (kWh/yr)c
Peak Demand Reduction (kW)d
NPV Avoided Costse
Non-Electric Benefit
Gross Incremental Participant Costf Incentive/Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 2 (electric FAF heating system w/o CAC)
Pre-existing duct leakage
Home Heating 20 80% 1,926.00 $2,188.67 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 2 (electric heat pump heating system)
Pre-existing duct leakage
Home Heating 20 80% 1,334.00 $1,515.93 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 3 (average heating system)
Pre-existing duct leakage
Home Heating 20 80% 2,426.00 $2,756.86 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 3 (electric FAF heating system w/CAC)
Pre-existing duct leakage
Home Heating 20 80% 2,599.00 $2,953.46 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured home duct tightness—PTCS duct sealing—heating zone 3 (electric FAF heating system w/o CAC)
Pre-existing duct leakage
Home Heating 20 80% 2,562.00 $2,911.41 $ – $ – $ – $0.398 2.28 2.28 1
Duct Sealing Manufactured
home duct tightness—PTCS duct sealing—heating zone 3 (electric heat pump heating system)
Pre-existing
duct leakage
Home Heating 20 80% 1,914.00 $2,175.04 $ – $ – $ – $0.398 2.28 2.28 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 24 Demand-Side Management 2011 Annual Report
a Average measure life.
b NTG percentage. Idaho Power Demand-Side management Potential Study. Nexant, Inc., 2009.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f No participant cost.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. Res_MHDuctSealingFY10v2_2.xls. 2011.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 25
ENERGY STAR® Homes Northwest
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 87,162 Test Benefit Cost Ratio
Program Incentives ............................................................. 172,600 I Utility Cost Test ................................... $ 967,191 $ 259,762 3.72
Total Utility Cost ................................................................. $ 259,762 P Total Resource Cost Test ................... 967,191 541,633 1.79
Ratepayer Impact Measure Test ......... 967,191 954,940 1.01
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 564,087 M Participant Cost Test ........................... 1,138,126 564,087 2.02

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 728,030 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 11,287,387 $ 1,343,321 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 1,343,321 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 965,526 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives Benefits ............................. $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) .......................................................................................... 72%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: 2006 International Energy Conservation Code (IECC) adopted in Idaho in 2008. 2009 IECC code adopted in Idaho in 2011.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 26 Demand-Side Management 2011 Annual Report
Year: 2011 Program: ENERGY STAR Homes Northwest Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
ENERGY STAR home
ENERGY STAR home initiated between January 1, 2008 and December 31, 2010.
Single-family home built to International Energy Conservation Code (IECC) 2006 Code. Adopted in 2008.
Home Residential 25 72% 1,402.00 2.40 $2,399.97 $ – $723.00 $400.00 $0.120 3.04 2.16 1
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/zonal
heat—heating zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 41 72% 4,752.00 $10,571.52 $ – $4,501.00 $1,000.00 $0.120 4.85 1.86 2
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/zonal heat—heating zone 2
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 42 72% 6,536.00 $14,685.77 $ – $4,501.00 $1,000.00 $0.120 5.93 2.46 2
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/zonal heat—heating zone 3
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 43 72% 7,470.00 $16,944.07 $ – $4,501.00 $1,000.00 $0.120 6.43 2.76 2
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 1 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 36 72% 3,555.00 $7,461.72 $ – $3,403.91 $1,000.00 $0.120 3.77 1.70 3
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 1 cooling zone 2
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 36 72% 3,633.00 $7,625.44 $ – $3,403.91 $1,000.00 $0.120 3.82 1.73 3

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 27
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/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 $8,032.81 $ – $3,403.91 $1,000.00 $0.120 3.98 1.82 3
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 2 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 39 72% 5,266.00 $11,466.14 $ – $3,403.91 $1,000.00 $0.120 5.06 2.46 3
ENERGY
STAR home
ENERGY
STAR Home in Idaho or Montana w/heat pump—heating zone 2 cooling zone 2
Single-family
home built to IECC 2009 Code. Adopted 2011.
Home Residential 39 72% 5,344.00 $11,635.98 $ – $3,403.91 $1,000.00 $0.120 5.10 2.48 3
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 2 cooling zone 3
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 39 72% 5,489.00 $11,951.70 $ – $3,403.91 $1,000.00 $0.120 5.19 2.54 3
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 3 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 6,710.00 $14,772.04 $ – $3,403.91 $1,000.00 $0.120 5.89 3.01 3
ENERGY
STAR home
ENERGY
STAR Home in Idaho or Montana w/heat pump—heating zone 3 cooling zone 2
Single-family
home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 6,787.00 $14,941.56 $ – $3,403.91 $1,000.00 $0.120 5.93 3.03 3
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana w/heat pump—heating zone 3 cooling zone 3
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 6,932.00 $15,260.78 $ – $3,403.91 $1,000.00 $0.120 6.00 3.08 3
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 28 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating zone 1 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 38 72% 5,079.00 $10,931.62 $ – $4,889.55 $1,000.00 $0.120 4.89 1.78 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating
zone 1 cooling zone 2
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 37 72% 4,996.00 $10,622.53 $ – $4,889.55 $1,000.00 $0.120 4.78 1.74 4
ENERGY STAR home
ENERGY STAR 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 $10,299.35 $ – $4,889.55 $1,000.00 $0.120 4.69 1.69 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating zone 2 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 7,165.00 $15,773.73 $ – $4,889.55 $1,000.00 $0.120 6.11 2.44 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built
to the DHP TCO—heating zone 2 cooling zone 2
Single-family home built to IECC 2009 Code.
Adopted 2011.
Home Residential 40 72% 7,082.00 $15,591.00 $ – $4,889.55 $1,000.00 $0.120 6.07 2.41 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating zone 2 cooling zone 3
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 6,930.00 $15,256.37 $ – $4,889.55 $1,000.00 $0.120 6.00 2.37 4

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 29
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating zone 3 cooling zone 1
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 8,248.00 $18,157.95 $ – $4,889.55 $1,000.00 $0.120 6.57 2.73 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating
zone 3 cooling zone 2
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 8,165.00 $17,975.22 $ – $4,889.55 $1,000.00 $0.120 6.54 2.71 4
ENERGY STAR home
ENERGY STAR Home in Idaho or Montana built to the DHP TCO—heating zone 3 cooling zone 3
Single-family home built to IECC 2009 Code. Adopted 2011.
Home Residential 40 72% 8,013.00 $17,640.59 $ – $4,889.55 $1,000.00 $0.120 6.48 2.67 4
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 Energy Savings and Peak Load Impacts of the Northwest Energy Star ® Program in Idaho Climate Zones IECC 2006 Base Standards for Idaho Power Company by Ecotope, Inc. Table 3.
2 RTF. EStarNWSFHomes_IDMTbop2_v1_1.xls. 2010. 3 RTF. EStarNWSFHomes_WAIDMT_FY10v2_0.xls. 2010.
4 RTF. EStarNWSFHomes_DHPtco_WAIDMT_v1_0.xls. 2010.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 30 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 31
Heating & Cooling Efficiency Program
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 137,720 Test Benefit Cost Ratio
Program Incentives ............................................................. 58,050 I Utility Cost Test ................................... $ 946,314 $ 195,770 4.83
Total Utility Cost ................................................................. $ 195,770 P Total Resource Cost Test ................... 946,314 530,772 1.78
Ratepayer Impact Measure Test ......... 946,314 786,554 1.20
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 476,803 M Participant Cost Test ........................... 796,530 476,803 1.67

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 733,405 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 9,536,038 $ 1,182,892 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 1,182,892 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 738,480 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives Benefits ............................. $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 32 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Heating & Cooling Efficiency Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
A/C/Heat Pump Units Evaporative cooler single family
Central A/C Unit Cooling 12 80% 1,393.73 $2,151.72 $ – $ – $150.00 $0.188 4.18 4.18 1
A/C/Heat Pump Units Evaporative
cooler manufactured home
Central A/C Unit Cooling 12 80% 1,393.73 $2,151.72 $ – $ – $150.00 $0.188 4.18 4.18 1
A/C/Heat Pump Units Open-loop water source heat pump—14.00 EER 3.5 COP
Electric resistance Unit Heating & cooling
20 80% 8,927.00 $13,481.73 $ – $1,650.00 $1,000.00 $0.188 4.03 3.37 2, 3
A/C/Heat Pump Units Open-loop water source heat pump—3.5 COP
Oil/Propane system Unit Heating & cooling
20 80% 8,927.00 $13,481.73 $ – $2,050.00 $1,000.00 $0.188 4.03 3.07 2, 3
A/C/Heat Pump Units New construction open-loop water source heat pump—14.00 EER 3.5 COP
Electric resistance Unit Heating & cooling
20 80% 8,927.00 $13,481.73 $ – $5,550.00 $1,000.00 $0.188 4.03 1.71 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 & cooling
20 80% 2,648.00 $3,999.06 $ – $600.00 $500.00 $0.188 3.21 2.97 2, 3
A/C/Heat Pump Units Single-family home HVAC conversions—convert to heat pump 8.20 HSPF heating zone 1 cooling zone 3
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 4,165.00 $6,290.06 $ – $4,554.00 $300.00 $0.188 4.65 1.12 4, 5
A/C/Heat Pump Units Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 1
Forced-air furnace w/central A/C
Unit Heating & cooling
20 80% 5,306.00 $8,013.22 $ – $4,554.00 $400.00 $0.188 4.59 1.36 4, 5

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 33
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 2
Forced-air furnace w/central A/C
Unit Heating & cooling
20 80% 6,961.00 $10,512.63 $ – $4,554.00 $400.00 $0.188 4.92 1.67 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 3
Forced-air furnace w/central A/C
Unit Heating & cooling
20 80% 7,876.00 $11,894.49 $ – $4,554.00 $400.00 $0.188 5.06 1.83 4, 5
A/C/Heat
Pump Units
Single-family
home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 1 cooling zone 1
Forced-air
furnace w/o central A/C
Unit Heating
& cooling
20 80% 5,064.00 $7,647.75 $ – $4,554.00 $400.00 $0.188 4.53 1.31 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat
pump 8.50 HSPF heating zone 1 cooling zone 2
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 4,796.00 $7,243.01 $ – $4,554.00 $400.00 $0.188 4.45 1.25 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat
pump 8.50 HSPF heating zone 1 cooling zone 3
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 4,380.00 $6,614.76 $ – $4,554.00 $400.00 $0.188 4.33 1.16 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 2 cooling zone 1
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 6,719.00 $10,147.16 $ – $4,554.00 $400.00 $0.188 4.88 1.63 4, 5

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 34 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 2 cooling zone 2
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 6,451.00 $9,742.42 $ – $4,554.00 $400.00 $0.188 4.83 1.58 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 2 cooling zone 3
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 6,035.00 $9,114.17 $ – $4,554.00 $400.00 $0.188 4.75 1.50 4, 5
A/C/Heat Pump Units
Single-family home HVAC conversions—convert to heat pump 8.50 HSPF heating zone 3 cooling zone 1
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 7,634.00 $11,529.01 $ – $4,554.00 $400.00 $0.188 5.03 1.79 4, 5
A/C/Heat Pump
Units
Single-family home HVAC
conversions—convert to heat pump 8.50 HSPF heating zone 3 cooling zone 2
Forced-air furnace w/o
central A/C
Unit Heating &
cooling
20 80% 7,366.00 $11,124.27 $ – $4,554.00 $400.00 $0.188 4.99 1.74 4, 5
A/C/Heat Pump Units
Single-family home HVAC
conversions—convert to heat pump 8.50 HSPF heating zone 3 cooling zone 3
Forced-air furnace w/o central A/C
Unit Heating & cooling
20 80% 6,950.00 $10,496.02 $ – $4,554.00 $400.00 $0.188 4.92 1.67 4, 5
A/C/Heat Pump Units
Existing single-family home heat pump: upgraded to 8.20 HSPF
Heat pump Unit Heating & cooling
20 80% 4,079.67 $6,161.19 $ – $970.17 $200.00 $0.188 5.10 3.11 2, 6
A/C/Heat Pump Units
Existing single-family home heat pump: upgraded to 8.50 HSPF
Heat pump Unit Heating & cooling
20 80% 4,176.67 $6,307.68 $ – $2,093.47 $250.00 $0.188 4.87 2.01 2, 6
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 35
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential—Residential Model Updated 081209.xlsm. 2009.
2 Savings from Ecotope, Inc., Heat Pump Sizing Specifications and Heat Pump Measure Savings Estimates. December 2009. 3 Costs from Portland Energy Conservation, Inc (PECI) program development and research. August 2007.
4 Savings from RTF. Res_SFHeatPumpsFY10v2_3.xls. 2010.
5 Costs from RTF. Res_SFHeatPumpsFY10v2_3.xls. 2010.
6 Costs from RTF presentation, Demand Measure Update: Revisited Heat Pumps (Weatherization, Duct Sealing). August 3, 2010.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 36 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 37
Home Improvement Program
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 179,168 Test Benefit Cost Ratio
Program Incentives ............................................................. 486,873 I Utility Cost Test ................................... $ 1,757,232 $ 666,041 2.64
Total Utility Cost ................................................................. $ 666,041 P Total Resource Cost Test ................... 1,757,232 2,297,061 0.76
Ratepayer Impact Measure Test ......... 1,757,232 1,802,756 0.97
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 2,525,648 M Participant Cost Test ........................... 1,907,767 2,525,648 0.76

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 917,519 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 15,321,338 $ 2,196,541 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 2,196,541 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 1,420,894 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: TRC would be higher if additional non-electric benefits (e.g., gas savings) were included. However, this was not pursued since most of the non-cost-effective measures failed the UC test, and all non-cost-effective attic insulation measures for non-electrically heated homes will be removed from the program as of April 1, 2012.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 38 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Home Improvement Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic 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 $3.95 $ – $0.40 $0.15 $0.195 6.66 4.69 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R19. Average
heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R0 to R19
ft2 Heating & cooling
45 80% 2.20 $5.23 $ – $0.40 $0.15 $0.195 7.22 5.37 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R19. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R19
ft2 Heating & cooling
45 80% 2.25 $5.36 $ – $0.40 $0.15 $0.195 7.27 5.43 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R19. Average heating system w/CAC. Heating
zone 3 cooling zone 1
Attic Insulation R0 to R19
ft2 Heating & cooling
45 80% 2.62 $6.21 $ – $0.40 $0.15 $0.195 7.53 5.78 1
Attic insulation Single-family home Weatherization: insulate attic 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 $5.41 $ – $0.80 $0.15 $0.195 7.28 3.89 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 39
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R0 to R38. Average heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 3.01 $7.16 $ – $0.80 $0.15 $0.195 7.76 4.56 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R38. Average
heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 3.09 $7.34 $ – $0.80 $0.15 $0.195 7.80 4.62 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R38. Average heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 3.58 $8.51 $ – $0.80 $0.15 $0.195 8.02 4.98 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R49. Average heating system w/CAC. Heating
zone 1 cooling zone 3
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 2.42 $5.75 $ – $1.03 $0.15 $0.195 7.39 3.47 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 3.20 $7.61 $ – $1.03 $0.15 $0.195 7.86 4.12 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 40 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R0 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 3.28 $7.80 $ – $1.03 $0.15 $0.195 7.89 4.18 1
Attic insulation Single-family home Weatherization: insulate attic R0 to R49. Average
heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 3.81 $9.05 $ – $1.03 $0.15 $0.195 8.11 4.53 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R30. Average heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.44 $1.06 $ – $0.23 $0.15 $0.195 3.57 2.80 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R30. Average heating system w/CAC. Heating
zone 2 cooling zone 2
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.59 $1.40 $ – $0.23 $0.15 $0.195 4.22 3.39 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R30. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.60 $1.43 $ – $0.23 $0.15 $0.195 4.28 3.45 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 41
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R19 to R30. Average heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.70 $1.66 $ – $0.23 $0.15 $0.195 4.64 3.78 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R38. Average
heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.61 $1.46 $ – $0.40 $0.15 $0.195 4.33 2.49 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R38. Average heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.81 $1.93 $ – $0.40 $0.15 $0.195 5.01 3.04 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R38. Average heating system w/CAC. Heating
zone 2 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.83 $1.98 $ – $0.40 $0.15 $0.195 5.07 3.09 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R38. Average heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.97 $2.30 $ – $0.40 $0.15 $0.195 5.43 3.41 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 42 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R19 to R49. Average heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 0.76 $1.80 $ – $0.63 $0.15 $0.195 4.84 2.11 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R49. Average
heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 1.00 $2.38 $ – $0.63 $0.15 $0.195 5.51 2.61 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 1.03 $2.44 $ – $0.63 $0.15 $0.195 5.58 2.66 1
Attic insulation Single-family home Weatherization: insulate attic R19 to R49. Average heating system w/CAC. Heating
zone 3 cooling zone 1
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 1.19 $2.83 $ – $0.63 $0.15 $0.195 5.92 2.95 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R38. Average heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.17 $0.40 $ – $0.17 $0.15 $0.195 1.76 1.63 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 43
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R30 to R38. Average heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.22 $0.53 $ – $0.17 $0.15 $0.195 2.20 2.05 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R38. Average
heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.23 $0.55 $ – $0.17 $0.15 $0.195 2.25 2.09 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R38. Average heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.27 $0.63 $ – $0.17 $0.15 $0.195 2.51 2.34 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R49. Average heating system w/CAC. Heating
zone 1 cooling zone 3
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.31 $0.74 $ – $0.40 $0.15 $0.195 2.82 1.45 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 2
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.41 $0.98 $ – $0.40 $0.15 $0.195 3.41 1.83 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 44 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R30 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.43 $1.01 $ – $0.40 $0.15 $0.195 3.47 1.87 1
Attic insulation Single-family home Weatherization: insulate attic R30 to R49. Average
heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.49 $1.17 $ – $0.40 $0.15 $0.195 3.81 2.10 1
Attic insulation Single-family home Weatherization: insulate attic R38 to R49. Average heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R38 to R49
ft2 Heating & cooling
45 80% 0.14 $0.34 $ – $0.23 $0.15 $0.195 1.53 1.12 1
Attic insulation Single-family home Weatherization: insulate attic R38 to R49. Average heating system w/CAC. Heating
zone 2 cooling zone 2
Attic Insulation R38 to R49
ft2 Heating & cooling
45 80% 0.19 $0.45 $ – $0.23 $0.15 $0.195 1.93 1.43 1
Attic insulation Single-family home Weatherization: insulate attic R38 to R49. Average heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R38 to R49
ft2 Heating & cooling
45 80% 0.19 $0.46 $ – $0.23 $0.15 $0.195 1.97 1.46 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 45
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home Weatherization: insulate attic R38 to R49. Average heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R38 to R49
ft2 Heating & cooling
45 80% 0.23 $0.54 $ – $0.23 $0.15 $0.195 2.21 1.66 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Average
electric heating system w/o CAC. Heating zone 1 cooling zone 3
Attic Insulation R0 to R19
ft2 Heating 45 80% 1.50 $2.84 $ – $0.40 $0.15 $0.195 5.14 3.54 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Average electric heating system w/o CAC. Heating zone 2 cooling zone 2
Attic Insulation R0 to R19
ft2 Heating 45 80% 2.09 $3.97 $ – $0.40 $0.15 $0.195 5.68 4.19 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Average electric heating system w/o CAC.
Heating zone 2 cooling zone 3
Attic Insulation R0 to R19
ft2 Heating 45 80% 2.09 $3.97 $ – $0.40 $0.15 $0.195 5.68 4.19 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Average electric heating system w/o CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R19
ft2 Heating 45 80% 2.54 $4.82 $ – $0.40 $0.15 $0.195 5.96 4.56 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 46 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $3.90 $ – $0.80 $0.15 $0.195 5.65 2.91 1
Attic insulation Single-family home weatherization: insulate attic 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 $5.43 $ – $0.80 $0.15 $0.195 6.13 3.54 1
Attic insulation Single-family home weatherization: insulate attic R0 to R38. Average electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R38
ft2 Heating 45 80% 2.87 $5.43 $ – $0.80 $0.15 $0.195 6.13 3.54 1
Attic insulation Single-family home weatherization: insulate attic 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 $6.60 $ – $0.80 $0.15 $0.195 6.36 3.92 1
Attic insulation Single-family home weatherization: insulate attic 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 $4.14 $ – $1.03 $0.15 $0.195 5.75 2.59 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 47
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $5.78 $ – $1.03 $0.15 $0.195 6.20 3.19 1
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Average
electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R49
ft2 Heating 45 80% 3.05 $5.78 $ – $1.03 $0.15 $0.195 6.20 3.19 1
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Average electric heating system w/o CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R49
ft2 Heating 45 80% 3.71 $7.02 $ – $1.03 $0.15 $0.195 6.43 3.56 1
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Average electric heating system w/o CAC.
Heating zone 1 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating 45 80% 0.40 $0.76 $ – $0.23 $0.15 $0.195 2.67 2.08 1
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Average electric heating system w/o CAC. Heating zone 2 cooling zone 2
Attic Insulation R19 to R30
ft2 Heating 45 80% 0.56 $1.06 $ – $0.23 $0.15 $0.195 3.28 2.62 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 48 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Average electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating 45 80% 0.56 $1.06 $ – $0.23 $0.15 $0.195 3.28 2.62 1
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Average
electric heating system w/o CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R30
ft2 Heating 45 80% 0.68 $1.29 $ – $0.23 $0.15 $0.195 3.65 2.97 1
Attic insulation Single-family home weatherization: insulate attic R19 to R38. Average electric heating system w/o CAC. Heating zone 1 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating 45 80% 0.56 $1.05 $ – $0.40 $0.15 $0.195 3.26 1.84 1
Attic insulation Single-family home weatherization: insulate attic 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 $1.47 $ – $0.40 $0.15 $0.195 3.90 2.35 1
Attic insulation Single-family home weatherization: insulate attic R19 to R38. Average electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating 45 80% 0.78 $1.47 $ – $0.40 $0.15 $0.195 3.90 2.35 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 49
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $1.78 $ – $0.40 $0.15 $0.195 4.28 2.68 1
Attic insulation Single-family home weatherization: insulate attic 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 $1.30 $ – $0.63 $0.15 $0.195 3.66 1.56 1
Attic insulation Single-family home weatherization: insulate attic 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 $1.81 $ – $0.63 $0.15 $0.195 4.31 2.01 1
Attic insulation Single-family home weatherization: insulate attic R19 to R49. Average electric heating system w/o CAC.
Heating zone 2 cooling zone 3
Attic Insulation R19 to R49
ft2 Heating 45 80% 0.96 $1.81 $ – $0.63 $0.15 $0.195 4.31 2.01 1
Attic insulation Single-family home weatherization: insulate attic 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 $2.20 $ – $0.63 $0.15 $0.195 4.68 2.31 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 50 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R30 to R38. Average electric heating system w/o CAC. Heating zone 1 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating 45 80% 0.15 $0.29 $ – $0.17 $0.15 $0.195 1.29 1.20 1
Attic insulation Single-family home weatherization: insulate attic 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 $0.41 $ – $0.17 $0.15 $0.195 1.69 1.57 1
Attic insulation Single-family home weatherization: insulate attic R30 to R38. Average electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating 45 80% 0.21 $0.41 $ – $0.17 $0.15 $0.195 1.69 1.57 1
Attic insulation Single-family home weatherization: insulate attic 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 $0.49 $ – $0.17 $0.15 $0.195 1.97 1.83 1
Attic insulation Single-family home weatherization: insulate attic 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 $0.54 $ – $0.40 $0.15 $0.195 2.09 1.06 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 51
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $0.75 $ – $0.40 $0.15 $0.195 2.64 1.41 1
Attic insulation Single-family home weatherization: insulate attic R30 to R49. Average
electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R30 to R49
ft2 Heating 45 80% 0.40 $0.75 $ – $0.40 $0.15 $0.195 2.64 1.41 1
Attic insulation Single-family home weatherization: insulate attic R30 to R49. Average electric heating system w/o CAC. Heating zone 3 cooling zone 1
Attic Insulation R30 to R49
ft2 Heating 45 80% 0.48 $0.91 $ – $0.40 $0.15 $0.195 2.99 1.65 1
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Average electric heating system w/o CAC.
Heating zone 1 cooling zone 3
Attic Insulation R38 to R49
ft2 Heating 45 80% 0.13 $0.25 $ – $0.23 $0.15 $0.195 1.12 0.82 1, 2
Attic insulation Single-family home weatherization: insulate attic 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 $0.34 $ – $0.23 $0.15 $0.195 1.48 1.10 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 52 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Average electric heating system w/o CAC. Heating zone 2 cooling zone 3
Attic Insulation R38 to R49
ft2 Heating 45 80% 0.18 $0.34 $ – $0.23 $0.15 $0.195 1.48 1.10 1
Attic insulation Single-family home weatherization: insulate attic 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 $0.42 $ – $0.23 $0.15 $0.195 1.73 1.30 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. No electric heating system w/CAC. Heating zone 1 cooling zone 3
Attic Insulation R0 to R19
ft2 Cooling 45 80% 0.16 $0.54 $ – $0.40 $0.15 $0.195 2.36 1.13 1
Attic insulation Single-family home weatherization: insulate attic 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 $0.35 $ – $0.40 $0.15 $0.195 1.66 0.77 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R19. No electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R19
ft2 Cooling 45 80% 0.16 $0.54 $ – $0.40 $0.15 $0.195 2.36 1.13 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 53
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R0 to R19. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R19
ft2 Cooling 45 80% 0.07 $0.24 $ – $0.40 $0.15 $0.195 1.18 0.53 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.73 $ – $0.80 $0.15 $0.195 3.03 0.82 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.48 $ – $0.80 $0.15 $0.195 2.15 0.55 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R38. No electric heating system w/CAC.
Heating zone 2 cooling zone 3
Attic Insulation R0 to R38
ft2 Cooling 45 80% 0.22 $0.73 $ – $0.80 $0.15 $0.195 3.03 0.82 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R38. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R0 to R38
ft2 Cooling 45 80% 0.10 $0.32 $ – $0.80 $0.15 $0.195 1.53 0.38 1, 3

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 54 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $0.78 $ – $1.03 $0.15 $0.195 3.18 0.69 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.51 $ – $1.03 $0.15 $0.195 2.26 0.46 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R49. No electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R0 to R49
ft2 Cooling 45 80% 0.23 $0.78 $ – $1.03 $0.15 $0.195 3.18 0.69 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R49. No electric heating system w/CAC.
Heating zone 3 cooling zone 1
Attic Insulation R0 to R49
ft2 Cooling 45 80% 0.10 $0.34 $ – $1.03 $0.15 $0.195 1.60 0.31 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.14 $ – $0.23 $0.15 $0.195 0.71 0.51 1, 3

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 55
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.23 $0.15 $0.195 0.46 0.33 1, 3
Attic insulation Single-family home weatherization: insulate attic R19 to R30. No
electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R30
ft2 Cooling 45 80% 0.04 $0.14 $ – $0.23 $0.15 $0.195 0.71 0.51 1, 3
Attic insulation Single-family home weatherization: insulate attic R19 to R30. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R30
ft2 Cooling 45 80% 0.02 $0.06 $ – $0.23 $0.15 $0.195 0.31 0.21 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.19 $ – $0.40 $0.15 $0.195 0.97 0.43 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.12 $ – $0.40 $0.15 $0.195 0.63 0.28 1, 3

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 56 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R19 to R38. No electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R38
ft2 Cooling 45 80% 0.06 $0.19 $ – $0.40 $0.15 $0.195 0.97 0.43 1, 3
Attic insulation Single-family home weatherization: insulate attic R19 to R38. No
electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R38
ft2 Cooling 45 80% 0.02 $0.08 $ – $0.40 $0.15 $0.195 0.41 0.18 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.24 $ – $0.63 $0.15 $0.195 1.17 0.35 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.15 $ – $0.63 $0.15 $0.195 0.77 0.22 1, 3
Attic insulation Single-family home weatherization: insulate attic R19 to R49. No electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R19 to R49
ft2 Cooling 45 80% 0.07 $0.24 $ – $0.63 $0.15 $0.195 1.17 0.35 1, 3

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 57
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R19 to R49. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R19 to R49
ft2 Cooling 45 80% 0.03 $0.10 $ – $0.63 $0.15 $0.195 0.50 0.14 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.17 $0.15 $0.195 0.28 0.25 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.17 $0.15 $0.195 0.18 0.16 1, 3
Attic insulation Single-family home weatherization: insulate attic R30 to R38. No electric heating system w/CAC.
Heating zone 2 cooling zone 3
Attic Insulation R30 to R38
ft2 Cooling 45 80% 0.02 $0.05 $ – $0.17 $0.15 $0.195 0.28 0.25 1, 3
Attic insulation Single-family home weatherization: insulate attic R30 to R38. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R30 to R38
ft2 Cooling 45 80% 0.01 $0.02 $ – $0.17 $0.15 $0.195 0.11 0.10 1, 3

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 58 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.40 $0.15 $0.195 0.50 0.22 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.40 $0.15 $0.195 0.32 0.14 1, 3
Attic insulation Single-family home weatherization: insulate attic R30 to R49. No electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R30 to R49
ft2 Cooling 45 80% 0.03 $0.10 $ – $0.40 $0.15 $0.195 0.50 0.22 1, 3
Attic insulation Single-family home weatherization: insulate attic R30 to R49. No electric heating system w/CAC.
Heating zone 3 cooling zone 1
Attic Insulation R30 to R49
ft2 Cooling 45 80% 0.01 $0.04 $ – $0.40 $0.15 $0.195 0.21 0.09 1, 3
Attic insulation Single-family home weatherization: insulate attic 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 $0.04 $ – $0.23 $0.15 $0.195 0.24 0.17 1, 3

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 59
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic 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 $ – $0.23 $0.15 $0.195 0.15 0.10 1, 3
Attic insulation Single-family home weatherization: insulate attic R38 to R49. No
electric heating system w/CAC. Heating zone 2 cooling zone 3
Attic Insulation R38 to R49
ft2 Cooling 45 80% 0.01 $0.04 $ – $0.23 $0.15 $0.195 0.24 0.17 1, 3
Attic insulation Single-family home weatherization: insulate attic R38 to R49. No electric heating system w/CAC. Heating zone 3 cooling zone 1
Attic Insulation R38 to R49
ft2 Cooling 45 80% 0.01 $0.02 $ – $0.23 $0.15 $0.195 0.09 0.07 1, 3
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R0 to R19
ft2 Heating & Cooling
45 80% 1.06 $2.52 $ – $0.40 $0.15 $0.195 5.65 3.63 1
Attic
insulation
Single-family
home weatherization: insulate attic R0 to R19. Heat pump. Heating zone 2 cooling zone 2
Attic
Insulation R0 to R19
ft2 Heating
& cooling
45 80% 1.65 $3.91 $ – $0.40 $0.15 $0.195 6.64 4.67 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 60 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R0 to R19
ft2 Heating & cooling
45 80% 1.70 $4.04 $ – $0.40 $0.15 $0.195 6.71 4.74 1
Attic insulation Single-family home weatherization: insulate attic R0 to R19. Heat pump.
Heating zone 3 cooling zone 1
Attic Insulation R0 to R19
ft2 Heating & cooling
45 80% 2.15 $5.10 $ – $0.40 $0.15 $0.195 7.17 5.31 1
Attic insulation Single-family home weatherization: insulate attic R0 to R38. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 1.44 $3.43 $ – $0.80 $0.15 $0.195 6.36 2.89 1
Attic insulation Single-family home weatherization: insulate attic R0 to R38. Heat pump. Heating zone 2 cooling zone 2
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 2.23 $5.29 $ – $0.80 $0.15 $0.195 7.24 3.83 1
Attic insulation Single-family home weatherization: insulate attic
R0 to R38. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 2.30 $5.47 $ – $0.80 $0.15 $0.195 7.30 3.91 1
Attic insulation Single-family home weatherization: insulate attic R0 to R38. Heat pump. Heating zone 3 cooling zone 1
Attic Insulation R0 to R38
ft2 Heating & cooling
45 80% 2.91 $6.90 $ – $0.80 $0.15 $0.195 7.70 4.47 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 61
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 1.53 $3.64 $ – $1.03 $0.15 $0.195 6.49 2.53 1
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Heat pump.
Heating zone 2 cooling zone 2
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 2.36 $5.60 $ – $1.03 $0.15 $0.195 7.35 3.41 1
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 2.44 $5.79 $ – $1.03 $0.15 $0.195 7.41 3.49 1
Attic insulation Single-family home weatherization: insulate attic R0 to R49. Heat pump. Heating zone 3 cooling zone 1
Attic Insulation R0 to R49
ft2 Heating & cooling
45 80% 3.08 $7.31 $ – $1.03 $0.15 $0.195 7.80 4.02 1
Attic insulation Single-family home weatherization: insulate attic
R19 to R30. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.28 $0.66 $ – $0.23 $0.15 $0.195 2.58 1.95 1
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Heat pump. Heating zone 2 cooling zone 2
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.42 $1.00 $ – $0.23 $0.15 $0.195 3.45 2.69 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 62 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.44 $1.04 $ – $0.23 $0.15 $0.195 3.53 2.76 1
Attic insulation Single-family home weatherization: insulate attic R19 to R30. Heat pump.
Heating zone 3 cooling zone 1
Attic Insulation R19 to R30
ft2 Heating & cooling
45 80% 0.55 $1.31 $ – $0.23 $0.15 $0.195 4.07 3.25 1
Attic insulation Single-family home weatherization: insulate attic R19 to R38. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.38 $0.91 $ – $0.40 $0.15 $0.195 3.23 1.71 1
Attic insulation Single-family home weatherization: insulate attic R19 to R38. Heat pump. Heating zone 2 cooling zone 2
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.58 $1.38 $ – $0.40 $0.15 $0.195 4.19 2.38 1
Attic insulation Single-family home weatherization: insulate attic
R19 to R38. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.60 $1.43 $ – $0.40 $0.15 $0.195 4.27 2.45 1
Attic insulation Single Family Home Weatherization - Insulate attic R19 to R38. Heat pump. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R38
ft2 Heating & cooling
45 80% 0.76 $1.80 $ – $0.40 $0.15 $0.195 4.84 2.90 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 63
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R19 to R49. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 0.47 $1.12 $ – $0.63 $0.15 $0.195 3.69 1.43 1
Attic insulation Single-family home weatherization: insulate attic R19 to R49. Heat pump.
Heating zone 2 cooling zone 2
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 0.71 $1.69 $ – $0.63 $0.15 $0.195 4.69 2.01 1
Attic insulation Single-family home weatherization: insulate attic R19 to R49. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 0.74 $1.76 $ – $0.63 $0.15 $0.195 4.78 2.07 1
Attic insulation Single-family home weatherization: insulate attic R19 to R49. Heat pump. Heating zone 3 cooling zone 1
Attic Insulation R19 to R49
ft2 Heating & cooling
45 80% 0.93 $2.22 $ – $0.63 $0.15 $0.195 5.34 2.48 1
Attic insulation Single-family home weatherization: insulate attic
R30 to R38. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.10 $0.25 $ – $0.17 $0.15 $0.195 1.17 1.08 1
Attic insulation Single-family home weatherization: insulate attic R30 to R38. Heat pump. Heating zone 2 cooling zone 2
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.16 $0.38 $ – $0.17 $0.15 $0.195 1.67 1.54 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 64 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R30 to R38. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.16 $0.39 $ – $0.17 $0.15 $0.195 1.72 1.59 1
Attic insulation Single-family home weatherization: insulate attic R30 to R38. Heat pump.
Heating zone 3 cooling zone 1
Attic Insulation R30 to R38
ft2 Heating & cooling
45 80% 0.21 $0.49 $ – $0.17 $0.15 $0.195 2.08 1.93 1
Attic insulation Single-family home weatherization: insulate attic R30 to R49. Heat pump. Heating zone 1 cooling zone 3
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.19 $0.46 $ – $0.40 $0.15 $0.195 1.95 0.95 1, 2
Attic insulation Single-family home weatherization: insulate attic R30 to R49. Heat pump. Heating zone 2 cooling zone 2
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.29 $0.69 $ – $0.40 $0.15 $0.195 2.68 1.37 1
Attic insulation Single-family home weatherization: insulate attic
R30 to R49. Heat pump. Heating zone 2 cooling zone 3
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.30 $0.72 $ – $0.40 $0.15 $0.195 2.75 1.41 1
Attic insulation Single-family home weatherization: insulate attic R30 to R49. Heat pump. Heating zone 3 cooling zone 1
Attic Insulation R30 to R49
ft2 Heating & cooling
45 80% 0.38 $0.91 $ – $0.40 $0.15 $0.195 3.24 1.71 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 65
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Costs
($/kWh)g UC Ratioh TRC Ratioi Source
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Heat pump. Heating zone 1 cooling zone 3
Attic insulation R38 to R49
ft2 Heating & cooling
45 80% 0.09 $0.21 $ – $0.23 $0.15 $0.195 1.00 0.72 1, 2
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Heat pump.
Heating zone 2 cooling zone 2
Attic insulation R38 to R49
ft2 Heating & cooling
45 80% 0.13 $0.32 $ – $0.23 $0.15 $0.195 1.44 1.05 1
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Heat pump. Heating zone 2 cooling zone 3
Attic insulation R38 to R49
ft2 Heating & cooling
45 80% 0.14 $0.33 $ – $0.23 $0.15 $0.195 1.49 1.09 1
Attic insulation Single-family home weatherization: insulate attic R38 to R49. Heat pump. Heating zone 3 cooling zone 1
Attic insulation R38 to R49
ft2 Heating & cooling
45 80% 0.17 $0.41 $ – $0.23 $0.15 $0.195 1.80 1.33 1
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP. f Incremental participant cost prior to customer incentive based on 2008–2010 actual customer costs.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((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-energy benefits will be reviewed and monitored in 2012.
3 Measure not cost-effective. Removed from the program in 2012.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 66 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 67
Home Products Program
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 152,005 Test Benefit Cost Ratio
Program Incentives ............................................................. 486,318 I Utility Cost Test ................................... $ 1,304,940 $ 638,323 2.04
Total Utility Cost ................................................................. $ 638,323 P Total Resource Cost Test ................... 1,419,449 1,344,446 1.06
Ratepayer Impact Measure Test ......... 1,304,940 1,614,982 0.81
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 1,368,972 M Participant Cost Test ........................... 1,821,651 1,368,972 1.33

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 1,485,326 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 16,571,356 $ 1,631,175 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 1,631,175 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 1,220,824 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ 114,509 NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: Non-electric benefits include the NPV of participant gas bill savings for ENERGY STAR® clothes washers. Based on RTF's assumption of therms saved per year and average retail gas rates for Intermountain Gas customers. Water savings will be researched in 2012.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 68 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Home Products Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefitf
Gross
Incremental Participant Costg Incentive/ Unit
Admin Cost
($/kWh)h UC Ratioi TRC Ratioj Source
Clothes washer ENERGY STAR® clothes washer modified energy factor (MEF) 2.00 to 2.19: any DHW, any dryer
Old clothes washers Washer Washer 14 80% 68.00 0.00 $67.61 $8.19 $36.72 $50.00 $0.118 0.93 1.31 1
Clothes washer ENERGY STAR clothes washer MEF 2.20 to 2.45: any DHW, any dryer
Old clothes washers Washer Washer 14 80% 113.00 0.00 $112.35 $11.92 $107.09 $50.00 $0.118 1.42 0.93 1, 2
Clothes washer ENERGY STAR clothes washer MEF 2.46 or higher: any DHW, any dryer
Old clothes washers Washer Washer 14 80% 170.00 0.00 $169.02 $16.49 $245.67 $50.00 $0.118 1.93 0.67 1, 2
Clothes washer ENERGY STAR clothes
washer, any MEF, any DHW, any dryer
Old clothes washers Washer Washer 14 80% 122.00 0.00 $121.30 $12.66 $80.43 $50.00 $0.118 1.51 1.24 1
Refrigerator ENERGY STAR refrigerator: bottom freezer w/ ice
through door
Old refrigerator Refrigerator First refrigerator 20 80% 45.00 0.00 $56.59 $ – $16.00 $30.00 $0.118 1.28 1.88 3
Refrigerator ENERGY STAR refrigerator: bottom freezer w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 40.00 0.00 $50.30 $ – $9.20 $30.00 $0.118 1.16 2.22 3
Refrigerator ENERGY STAR refrigerator: side-by-side w/ ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 44.00 0.00 $55.33 $ – $31.70 $30.00 $0.118 1.26 1.21 3
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 69
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefitf
Gross
Incremental Participant Costg Incentive/ Unit
Admin Cost
($/kWh)h UC Ratioi TRC Ratioj Source
Refrigerator ENERGY STAR refrigerator: side-by-side w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 51.00 0.00 $64.14 $ – $37.71 $30.00 $0.118 1.42 1.22 3
Refrigerator ENERGY
STAR refrigerator: top freezer w/ ice through door
Old
refrigerator
Refrigerator First
refrigerator
20 80% 40.00 0.00 $50.30 $ – $12.34 $30.00 $0.118 1.16 1.95 3
Refrigerator ENERGY STAR refrigerator:
top freezer w/o ice through door
Old refrigerator Refrigerator First refrigerator 20 80% 45.00 0.00 $56.59 $ – $14.08 $30.00 $0.118 1.28 2.00 3
Refrigerator ENERGY STAR refrigerator
Old refrigerator Refrigerator First refrigerator 20 80% 44.00 0.00 $55.33 $ – $19.47 $30.00 $0.118 1.26 1.65 3
Freezer ENERGY STAR freezer: no tiers, chest, any defrost
Old freezer Freezer Freezer 20 80% 35.00 0.00 $44.15 $ – $3.74 $20.00 $0.118 1.46 3.17 4
Freezer ENERGY STAR freezer: no tiers, upright, automatic defrost
Old freezer Freezer Freezer 20 80% 61.00 0.00 $76.95 $ – $5.60 $20.00 $0.118 2.26 3.92 4
Freezer ENERGY STAR
freezer: no tiers, upright, manual defrost
Old freezer Freezer Freezer 20 80% 39.00 0.00 $49.20 $ – $3.28 $20.00 $0.118 1.60 3.50 4
Freezer ENERGY STAR freezer No tiers. Any upright
Old freezer Freezer Freezer 20 80% 53.00 0.00 $66.86 $ – $4.79 $20.00 $0.118 2.04 3.79 4
Freezer ENERGY STAR freezer: no tiers, any freezer
Old freezer Freezer Freezer 20 80% 42.00 0.00 $52.98 $ – $4.16 $20.00 $0.118 1.70 3.45 4
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 70 Demand-Side Management 2011 Annual Report

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure Life (years)a NTGb
Annual Gross Energy Savings (kWh/yr)c
Peak Demand Reduction (kW)d
NPV Avoided Costse
Non-Electric Benefitf
Gross Incremental Participant Costg Incentive/ Unit
Admin Cost
($/kWh)h UC Ratioi TRC Ratioj Source
Lighting ENERGY
STAR LED light fixture
Incandescent
light fixture
Fixture Lighting 12 100% 35.00 $27.44 $ – $47.00 $15.00 $0.118 1.43 0.54 5, 6
Lighting ENERGY STAR light fixture: weighted average all
Incandescent light fixture Fixture Lighting 15 100% 49.00 $47.24 $ – $19.64 $15.00 $0.118 2.27 1.86 7
Lighting ENERGY STAR ceiling fan light kits
Incandescent ceiling fan light kit
Fixture Lighting 6 100% 32.00 $12.67 $ – $44.00 $15.00 $0.118 0.67 0.27 6, 8
Lighting ENERGY STAR ceiling fan
Old ceiling fan Fixture Cooling 10 80% 59.00 $78.39 $ – $86.00 $20.00 $0.118 2.33 0.79 6, 9
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 $44.38 $ – $24.00 $7.00 $0.040 3.67 1.53 10
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 $66.31 $ – $24.00 $7.00 $0.040 4.83 2.16 10
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 $85.82 $ – $24.00 $7.00 $0.040 5.64 2.66 10
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Sum of NPV of participant gas bill savings.
g Incremental participant cost prior to customer incentive.
h Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
i Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
j Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. ResClothesWashersSF_FY10v2_0.xls. 2010. 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 cost and other non-electric (e.g., gas and water) benefits will be reviewed and monitored in 2012.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 71
3 RTF. ResRefrigerator_v2_1.xls. 2010.
4 RTF. ResFreezerFY10v2_0.xls. 2010.
5 RTF. ResSpecialtyLighting_v1_1.xlsml. Any Location. 2011.
6 Measure not cost-effective. Removed from the program in 2012.
7 RTF. ResCFLLighting_v2_1.xlsm. 2011.
8 RTF. ResCFLLighting_v2_1.xlsm. 2011. Savings of 2 retail CFL bulbs at 16 kWh/year.
9 ADM Associates, Inc., Impact Evaluation of 2010 Home Products Program. 2011.
10 RTF. ResShowerheads_v2_1.xlsm. 2011. Adjusted savings by changing Electric Water Heating saturation from 64% to 52% to match IPC mix.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 72 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 73
Rebate Advantage
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 50,969 Test Benefit Cost Ratio
Program Incentives ............................................................. 12,500 I Utility Cost Test ................................... $ 183,939 $ 63,469 2.90
Total Utility Cost ................................................................. $ 63,469 P Total Resource Cost Test ................... 183,939 80,729 2.28
Ratepayer Impact Measure Test ......... 183,939 211,303 0.87
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 34,075 M Participant Cost Test ........................... 197,294 34,075 5.79

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 159,325 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 2,273,276 $ 229,923 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 229,923 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 184,793 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) .......................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 74 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi 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 $7,526.54 $ – $1,362.62 $500.00 $0.320 2.69 2.06 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 $9,759.25 $ – $1,362.62 $500.00 $0.320 2.90 2.31 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 $11,483.90 $ – $1,362.62 $500.00 $0.320 2.98 2.44 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 & cooling
23 80% 3,128.00 $5,219.27 $ – $1,362.62 $500.00 $0.320 2.78 1.91 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 & cooling
23 80% 3,172.00 $5,292.69 $ – $1,362.62 $500.00 $0.320 2.79 1.92 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 & cooling
23 80% 3,254.00 $5,429.51 $ – $1,362.62 $500.00 $0.320 2.82 1.95 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 & cooling
25 80% 4,346.00 $7,662.45 $ – $1,362.62 $500.00 $0.320 3.24 2.38 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 75

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure Life (years)a NTGb
Annual Gross Energy Savings (kWh/yr)c
Peak Demand Reduction (kW)d
NPV Avoided Costse
Non-Electric Benefit
Gross Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
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
& cooling
25 80% 4,390.00 $7,740.03 $ – $1,362.62 $500.00 $0.320 3.25 2.39 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 & cooling
25 80% 4,472.00 $7,884.60 $ – $1,362.62 $500.00 $0.320 3.27 2.41 1
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 & cooling
26 80% 5,516.00 $9,969.91 $ – $1,362.62 $500.00 $0.320 3.52 2.70 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 & cooling
26 80% 5,560.00 $10,049.44 $ – $1,362.62 $500.00 $0.320 3.53 2.71 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 & cooling
26 80% 5,642.00 $10,197.65 $ – $1,362.62 $500.00 $0.320 3.54 2.72 1
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses. e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. NewMH_EStar_EcoRated_v1_2.xls. 2010.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 76 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 77
See ya later, refrigerator®
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 556,323 Test Benefit Cost Ratio
Program Incentives ............................................................. 98,070 I Utility Cost Test ................................... $ 994,718 $ 654,393 1.52
Total Utility Cost ................................................................. $ 654,393 P Total Resource Cost Test ................... 994,718 654,393 1.52
Ratepayer Impact Measure Test ......... 994,718 1,503,761 0.66
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ — M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 1,712,423 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 12,502,293 $ 994,718 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 994,718 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ N/A N/A
NPV Cumulative Participant Savings............. $ 849,368 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) .......................................................................................... 100%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
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 78 Demand-Side Management 2011 Annual Report
Year: 2011 Program: See ya later, refrigerator Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Refrigerator recycling Refrigerator removal and decommissioning
Refrigerator Second Refrigerator 9 100% 482.00 $294.97 $ – $ – $30.00 $0.325 1.58 1.58 1
Freezer recycling Freezer removal
and decommissioning
Freezer Freezer 6 100% 555.00 $227.45 $ – $ – $30.00 $0.325 1.08 1.08 1
a Average measure life.
b No NTG. Deemed savings from RTF includes realization rate.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f No participant cost.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals. h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. FrigRecycle_FY10v2_3.xls. 2010.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 79
Weatherization Assistance for Qualified Customers
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 1,324,415 Test Benefit Cost Ratio
Program Incentives ............................................................. — I Utility Cost Test ................................... $ 3,531,604 $ 1,324,415 2.67
Total Utility Cost ................................................................. $ 1,324,415 P Total Resource Cost Test ................... 3,531,604 2,730,521 1.29
Ratepayer Impact Measure Test ......... 3,531,604 3,907,311 0.90
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 1,757,632 M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 2,783,648 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 39,760,765 $ 4,414,505 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 4,414,505 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ N/A N/A
NPV Cumulative Participant Savings............. $ 3,228,621 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) .......................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: Energy savings for each home determined by an auditor using an Energy Audit 4 (EA4) form approved by the Department of Energy (DOE). Cost-effectiveness analyzed on a per project basis. Each project must have a savings to investment ratio (SIR) equal to or greater than 1. No customer participant costs. Costs shown are from the DOE state weatherization assistance program.

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Page 80 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 81
Weatherization Solutions for Eligible Customers
Segment: Residential
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 788,148 Test Benefit Cost Ratio
Program Incentives ............................................................. — I Utility Cost Test ................................... $ 1,447,829 $ 788,148 1.84
Total Utility Cost ................................................................. $ 788,148 P Total Resource Cost Test ................... 1,447,829 788,148 1.84
Ratepayer Impact Measure Test ......... 1,447,829 1,847,041 0.78
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ – M Participant Cost Test ........................... N/A N/A N/A

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 1,141,194 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 16,300,461 $ 1,809,786 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 1,809,786 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ N/A N/A
NPV Cumulative Participant Savings............. $ 1,323,616 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.072
Line Losses ....................................................................................................... 10.90%
Notes: Energy savings for each home determined by an auditor using an Energy Audit 4 (EA4) form approved by the Department of Energy (DOE). Cost-effectiveness analyzed on a per project basis. Each project must have a savings to investment ratio (SIR) equal to or greater than 1. No participant costs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 82 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Weatherization Solutions for Eligible Customers Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Windows Home Heating & cooling 15 80% 2,367.85 $2,842.55 $ – $ – $0.691 1.39 1.39 1
Doors Home Heating & cooling 15 80% 491.13 $589.59 $ – $ – $0.691 1.39 1.39 1
Walls Home Heating & cooling 20 80% 3,004.56 $4,537.54 $ – $ – $0.691 1.75 1.75 1
Ceilings Home Heating &
cooling
20 80% 1,113.05 $1,680.95 $ – $ – $0.691 1.75 1.75 1
Venting Home Other N/A N/A N/A N/A $ – $ – $0.691 N/A N/A 2
Floors Home Heating & cooling 20 80% 1,071.83 $1,618.70 $ – $ – $0.691 1.75 1.75 1
Infiltration Home Heating & cooling 15 80% 1,472.24 $1,767.39 $ – $ – $0.691 1.39 1.39 1
Ducts Home Heating & cooling 20 80% 2,155.82 $3,255.76 $ – $ – $0.691 1.75 1.75 1
Health & safety Home Other N/A N/A N/A N/A $ – $ – $0.691 N/A N/A 2
Other Investment Home Other N/A N/A N/A N/A $ – $ – $0.476 N/A N/A 2
Water heater Home Water Heating 10 80% 205.92 $136.85 $ – $ – $0.691 0.77 0.77 1,3
Pipes Home Water Heating 15 80% 31.92 $31.01 $ – $ – $0.691 1.12 1.12 1
Refrigerator replacement Home First Refrigerator 20 80% 1,045.00 $1,314.17 $ – $ – $0.691 1.46 1.46 1
Furnace
modify
Home Heating 3 80% N/A $- $ – $ – $0.691 N/A N/A 4
Furnace repair Home Other N/A N/A N/A N/A $ – $ – $0.691 N/A N/A 2
Furnace replacement Home Heating 20 80% 2,348.41 $2,668.69 $ – $ – $0.691 1.32 1.32 1
Furnace tune up Home Heating 3 80% 33.91 $5.77 $ – $ – $0.691 0.20 0.20 1,3
CFLs Home Lighting 7 80% 167.31 $77.51 $ – $ – $0.691 0.54 0.54 1,3
Audit investment Home Other N/A N/A N/A N/A $ – $ – $0.691 N/A N/A 2
a Average measure life.
b 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.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 83
d Estimated peak demand reduction measured at the customer’s meter, excluding line losses. e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f No participant cost.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 Average actual 2011 program savings across all projects as estimated from energy audit calculations.
2 Non-energy savings measure allowed by the program to help facilitate effective performance of other energy saving measures.
3 Measure not cost-effective due to high administration costs. Measure bundled with other cost-effective measures.
4 No measures installed by contractors in 2011.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 84 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 85
Building Efficiency
Segment: Commercial
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 281,339 Test Benefit Cost Ratio
Program Incentives ............................................................. 1,010,086 I Utility Cost Test ................................... $ 7,627,364 $ 1,291,425 5.91
Total Utility Cost ................................................................. $ 1,291,425 P Total Resource Cost Test ................... 7,627,364 2,914,297 2.62
Ratepayer Impact Measure Test ......... 7,627,364 5,424,965 1.41
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 3,038,676 M Participant Cost Test ........................... 6,177,011 3,038,676 2.03

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 11,514,641 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 111,951,106 $ 9,534,205 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 9,534,205 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 5,166,925 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.047
Line Losses ....................................................................................................... 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 86 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Building Efficiency Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Lighting controls Interior light load reduction: 10–19% below code
ft2 Lighting 11 96% 0.38 0.00 $0.30 $ – $0.05 $0.05 $0.024 4.86 4.86 1
Lighting controls Interior light
load reduction: 20% or more below code
ft2 Lighting 11 96% 1.09 0.00 $0.86 $ – $0.10 $0.15 $0.024 4.67 6.42 1
Lighting controls Exterior light load reduction: 15% or more below code
kW Outdoor Lighting 11 96% 4,059.00 0.00 $2,271.41 $ – $205.00 $200.00 $0.024 7.29 7.17 2
Lighting controls Daylight photo controls
Sensor Lighting 8 96% 132.00 0.00 $76.81 $ – $50.00 $15.00 $0.024 4.05 1.42 1
Lighting controls Occupancy sensors Sensor Lighting 8 96% 289.99 – $168.74 $ – $77.00 $25.00 $0.024 5.05 1.98 3
Sign lighting High efficiency exit signs
Signs Lighting 16 96% 333.00 0.03 $368.07 $ – $31.52 $7.50 $0.024 22.60 9.13 3
A/C/Heat Pump Units Premium efficiency HVAC unit
Ton HVAC 15 80% 386.72 0.32 $498.59 $ – $122.22 $50.00 $0.024 6.71 3.40 1
A/C/Heat Pump Units Additional HVAC unit efficiency bonus
Ton HVAC 15 80% 181.78 0.01 $234.37 $ – $81.50 $25.00 $0.024 6.37 2.51 1
A/C/Heat Pump Units Efficient chillers Ton HVAC 15 80% 154.28 0.17 $198.91 $ – $75.00 $20.00 $0.024 6.69 2.35 2
Economizers Air-side economizers Ton HVAC 15 80% 300.00 0.11 $386.79 $ – $170.00 $75.00 $0.024 3.76 1.95 3
Reflective roofing Reflective roof coating ft2 HVAC 15 80% 0.41 0.00 $0.53 $ – $0.35 $0.05 $0.024 7.05 1.41 3
Efficient windows High performance windows
ft2 HVAC 30 80% 1.01 0.00 $2.10 $ – $0.74 $0.50 $0.024 3.21 2.35 3
Automated control systems Energy management control systems
ft2 HVAC 14 96% 1.24 – $1.51 $ – $1.00 $0.30 $0.024 4.39 1.45 3
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 87
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Automated control systems Demand controlled ventilation
Ft3/minute HVAC 10 96% 1.31 – $1.19 $ – $0.60 $0.50 $0.024 2.15 1.82 3
Variable speed controls Variable speed drives HP HVAC 15 96% 985.02 – $1,269.97 $ – $187.00 $60.00 $0.024 14.58 5.93 3
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals. h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((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 Potential Study assumptions.
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 88 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 89
Custom Efficiency
Segment: Industrial
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 1,054,230 Test Benefit Cost Ratio
Program Incentives ............................................................. 7,729,581 I Utility Cost Test ................................... $ 56,287,228 $ 8,783,811 4.42
Total Utility Cost ................................................................. $ 8,783,811 P Total Resource Cost Test ................... 56,287,228 19,830,834 2.37
Ratepayer Impact Measure Test ......... 56,287,228 26,271,960 1.86
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 18,776,604 M Participant Cost Test ........................... 25,217,730 18,776,604 1.34

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 67,979,157 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 660,927,404 $ 56,287,228 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 56,287,228 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 17,488,150 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 69%
Average 2011 Customer Segment Rate/kWh .................................................... $0.027
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 15 to 5,000 HP. Commercial and industrial motor rewinds are paid under Custom Efficiency. NTG of 69% from CPUC DEER NTFR Update Process for 2006-2007 Programs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 90 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Custom Efficiency–Green Motors Market Segment: Industrial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 15HP
Green Motors Program Rewind: motor size 15HP
Standard rewind practice
Motor MF_Motors 12 69% 274.02 $222.31 $ – $138.33 $30.00 $0.050 3.51 1.30 1
Green Motors Program Rewind: motor size 20HP
Green Motors Program Rewind: motor size 20HP
Standard rewind practice
Motor MF_Motors 12 69% 362.55 $294.14 $ – $154.33 $40.00 $0.050 3.49 1.48 1
Green
Motors Program Rewind: motor size 25HP
Green
Motors Program Rewind: motor size 25HP
Standard
rewind practice
Motor MF_Motors 11 69% 534.72 $400.30 $ – $176.33 $50.00 $0.050 3.60 1.69 1
Green Motors Program
Rewind: motor size 30HP
Green Motors Program
Rewind: motor size 30HP
Standard rewind practice
Motor MF_Motors 11 69% 574.63 $430.18 $ – $193.67 $60.00 $0.050 3.35 1.64 1
Green Motors Program Rewind: motor size 40HP
Green Motors Program Rewind: motor size 40HP
Standard rewind practice
Motor MF_Motors 11 69% 671.75 $502.89 $ – $236.67 $80.00 $0.050 3.05 1.57 1
Green Motors Program Rewind: motor size 50HP
Green Motors Program Rewind: motor size 50HP
Standard rewind practice
Motor MF_Motors 11 69% 728.65 $545.48 $ – $262.00 $100.00 $0.050 2.76 1.52 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 91
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh
TRC
Ratioi Source
Green Motors Program Rewind: motor size 60HP
Green Motors Program Rewind: motor size 60HP
Standard rewind practice
Motor MF_Motors 9 69% 970.56 $599.36 $ – $309.00 $120.00 $0.050 2.45 1.38 1
Green Motors Program Rewind: motor size 70HP
Green Motors Program Rewind: motor size 70HP
Standard rewind practice
Motor MF_Motors 9 69% 1,008.53 $622.81 $ – $334.00 $150.00 $0.050 2.14 1.31 1
Green
Motors Program Rewind: motor size 100HP
Green
Motors Program Rewind: motor size 100HP
Standard
rewind practice
Motor MF_Motors 9 69% 1,558.33 $962.34 $ – $414.33 $200.00 $0.050 2.39 1.56 1
Green Motors Program Rewind: motor
size 125HP
Green Motors Program Rewind: motor size
125HP
Standard rewind practice
Motor MF_Motors 10 69% 1,891.23 $1,293.18 $ – $465.33 $250.00 $0.050 2.59 1.81 1
Green Motors Program Rewind: motor size 150HP
Green Motors Program Rewind: motor size 150HP
Standard rewind practice
Motor MF_Motors 10 69% 2,253.74 $1,541.06 $ – $518.33 $300.00 $0.050 2.58 1.89 1
Green Motors Program Rewind: motor size 200HP
Green Motors Program Rewind: motor size 200HP
Standard rewind practice
Motor MF_Motors 10 69% 2,986.91 $2,042.39 $ – $624.00 $400.00 $0.050 2.57 2.00 1
Green Motors Program Rewind: motor size 250HP
Green Motors Program Rewind: motor size 250HP
Standard rewind practice
Motor MF_Motors 8 69% 4,396.67 $2,418.93 $ – $802.00 $500.00 $0.050 2.32 1.80 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 92 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh
TRC
Ratioi Source
Green Motors Program Rewind: motor size 300HP
Green Motors Program Rewind: motor size 300HP
Standard rewind practice
Motor MF_Motors 8 69% 5,268.52 $2,898.60 $ – $810.67 $600.00 $0.050 2.32 1.98 1
Green Motors Program Rewind: motor size 350HP
Green Motors Program Rewind: motor size 350HP
Standard rewind practice
Motor MF_Motors 8 69% 6,146.61 $3,381.71 $ – $849.67 $700.00 $0.050 2.32 2.10 1
Green
Motors Program Rewind: motor size 400HP
Green
Motors Program Rewind: motor size 400HP
Standard
rewind practice
Motor MF_Motors 8 69% 7,005.00 $3,853.97 $ – $949.00 $800.00 $0.050 2.31 2.12 1
Green Motors Program Rewind: motor
size 450HP
Green Motors Program Rewind: motor size
450HP
Standard rewind practice
Motor MF_Motors 8 69% 7,858.73 $4,323.67 $ – $1,037.33 $900.00 $0.050 2.31 2.15 1
Green Motors Program Rewind: motor size 500HP
Green Motors Program Rewind: motor size 500HP
Standard rewind practice
Motor MF_Motors 8 69% 8,731.93 $4,804.08 $ – $1,120.67 $1,000.00 $0.050 2.31 2.18 1
Green Motors Program Rewind: motor size 600HP
Green Motors Program Rewind: motor size 600HP
Standard rewind practice
Motor MF_Motors 7 69% 12,279.22 $5,916.03 $ – $1,651.45 $1,200.00 $0.050 2.25 1.92 1
Green Motors Program Rewind: motor size 700HP
Green Motors Program Rewind: motor size 700HP
Standard rewind practice
Motor MF_Motors 7 69% 14,325.76 $6,902.03 $ – $1,801.73 $1,400.00 $0.050 2.25 1.99 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 93
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh
TRC
Ratioi Source
Green Motors Program Rewind: motor size 800HP
Green Motors Program Rewind: motor size 800HP
Standard rewind practice
Motor MF_Motors 7 69% 16,372.29 $7,888.04 $ – $1,999.06 $1,600.00 $0.050 2.25 2.02 1
Green Motors Program Rewind: motor size 900HP
Green Motors Program Rewind: motor size 900HP
Standard rewind practice
Motor MF_Motors 7 69% 18,418.83 $8,874.04 $ – $2,203.88 $1,800.00 $0.050 2.25 2.04 1
Green
Motors Program Rewind: motor size 1000HP
Green
Motors Program Rewind: motor size 1000HP
Standard
rewind practice
Motor MF_Motors 7 69% 21,177.35 $10,203.08 $ – $2,375.10 $2,000.00 $0.050 2.30 2.12 1
Green Motors Program Rewind: motor
size 1250HP
Green Motors Program Rewind: motor size
1250HP
Standard rewind practice
Motor MF_Motors 7 69% 26,471.69 $12,753.85 $ – $2,837.23 $2,500.00 $0.050 2.30 2.17 1
Green Motors Program Rewind: motor size 1500HP
Green Motors Program Rewind: motor size 1500HP
Standard rewind practice
Motor MF_Motors 7 69% 31,766.03 $15,304.62 $ – $3,250.13 $3,000.00 $0.050 2.30 2.22 1
Green Motors Program Rewind: motor size 1750HP
Green Motors Program Rewind: motor size 1750HP
Standard rewind practice
Motor MF_Motors 7 69% 37,060.37 $17,855.39 $ – $3,709.54 $3,500.00 $0.050 2.30 2.24 1
Green Motors Program Rewind: motor size 2000HP
Green Motors Program Rewind: motor size 2000HP
Standard rewind practice
Motor MF_Motors 7 69% 42,354.70 $20,406.16 $ – $4,161.19 $4,000.00 $0.050 2.30 2.26 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 94 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh
TRC
Ratioi Source
Green Motors Program Rewind: motor size 2250HP
Green Motors Program Rewind: motor size 2250HP
Standard rewind practice
Motor MF_Motors 7 69% 47,649.04 $22,956.93 $ – $4,533.29 $4,500.00 $0.050 2.30 2.29 1
Green Motors Program Rewind: motor size 2500HP
Green Motors Program Rewind: motor size 2500HP
Standard rewind practice
Motor MF_Motors 7 69% 52,943.38 $25,507.70 $ – $4,959.78 $5,000.00 $0.050 2.30 2.31 1, 2
Green
Motors Program Rewind: motor size 3000HP
Green
Motors Program Rewind: motor size 3000HP
Standard
rewind practice
Motor MF_Motors 7 69% 63,532.05 $30,609.24 $ – $5,798.90 $6,000.00 $0.050 2.30 2.34 1, 2
Green Motors Program Rewind: motor
size 3500HP
Green Motors Program Rewind: motor size
3500HP
Standard rewind practice
Motor MF_Motors 7 69% 74,120.73 $35,710.77 $ – $6,408.05 $7,000.00 $0.050 2.30 2.39 1, 2
Green Motors Program Rewind: motor size 4000HP
Green Motors Program Rewind: motor size 4000HP
Standard rewind practice
Motor MF_Motors 7 69% 84,709.41 $40,812.31 $ – $7,154.28 $8,000.00 $0.050 2.30 2.42 1, 2
Green Motors Program Rewind: motor size 4500HP
Green Motors Program Rewind: motor size 4500HP
Standard rewind practice
Motor MF_Motors 7 69% 95,298.08 $45,913.85 $ – $7,710.11 $9,000.00 $0.050 2.30 2.46 1, 2
Green Motors Program Rewind: motor size 5000HP
Green Motors Program Rewind: motor size 5000HP
Standard rewind practice
Motor MF_Motors 7 69% 105,886.76 $51,015.39 $ – $8,230.18 $10,000.00 $0.050 2.30 2.50 1, 2
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 95
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. GreenMotorsRewind_Ind_FY10v1_2.xls. 2010.
2 Incentive greater than incremental cost. This is a regional initiative sponsored by the RTF and Green Motors Practices Group (GMPG). Costs and savings deemed by RTF and incentives set by GMPG. One incentive paid on pump greater than 650hp in 2011.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 96 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 97
Easy Upgrades
Segment: Commercial
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 814,874 Test Benefit Cost Ratio
Program Incentives ............................................................. 3,904,592 I Utility Cost Test ................................... $ 25,650,385 $ 4,719,466 5.44
Total Utility Cost ................................................................. $ 4,719,466 P Total Resource Cost Test ................... 25,650,385 8,559,384 3.00
Ratepayer Impact Measure Test ......... 25,650,385 18,620,323 1.38
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 8,704,490 M Participant Cost Test ........................... 21,280,663 8,704,490 2.44

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 38,723,073 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 376,485,106 $ 32,062,981 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 32,062,981 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M - I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 17,376,071 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ — NEB Real ((1 + WACC) / (1 + Escalation)) - 1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 80%
Average 2011 Customer Segment Rate/kWh .................................................... $0.047
Line Losses ....................................................................................................... 10.90%
Notes: 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 98 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Easy Upgrades Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross Incrementa
l Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
2010—T8 fluorescents 1- or 2-lamp 4' T8 fixture 1- or 2-lamp 4' T12 fixture
Fixture Lighting 11 96% 69.00 0.02 $54.44 $ – $17.55 $14.00 $0.021 3.38 2.77 1
2010—T8 fluorescents 3-lamp 4' T8 fixture 3-lamp 4' T12 fixture Fixture Lighting 11 96% 144.99 0.03 $114.40 $ – $35.10 $24.00 $0.021 4.06 2.91 1
2010—T8 fluorescents 4-lamp 4' T8 fixture 4-lamp 4' T12 fixture Fixture Lighting 11 96% 190.97 0.04 $150.67 $ – $46.80 $32.00 $0.021 4.02 2.88 1
2010—T8 fluorescents 1- or 2-lamp 8' T8 fixture 1- or 2-lamp 8' T12 fixture
Fixture Lighting 11 96% 99.02 0.02 $78.13 $ – $55.00 $26.00 $0.021 2.67 1.34 1
2010—T8 fluorescents 1- or 2-lamp 8' T8 HO fixture 1- or 2-lamp 8' T12 HO fixture
Fixture Lighting 11 96% 272.31 0.06 $214.85 $ – $81.25 $46.00 $0.021 3.99 2.41 1
2010—T8 fluorescents 4-lamp 4' T8 high-bay fixture Fixture drawing 250 W or more
Fixture Lighting 11 96% 495.10 0.12 $390.64 $ – $250.00 $80.00 $0.021 4.15 1.48 1
2010—T8 fluorescents 6-lamp 4' T8 high-bay fixture Fixture drawing 400 W or more
Fixture Lighting 11 96% 813.38 0.19 $641.76 $ – $300.00 $120.00 $0.021 4.49 1.99 1
2010—T8 fluorescents 8-lamp 4' T8 high-bay fixture Fixture drawing 750 W or more
Fixture Lighting 12 96% 902.44 $770.95 $ – $327.20 $190.00 $0.021 3.54 2.17 2
2010—T8 fluorescents Low-wattage T8 lamp Standard wattage T8 lamp
Lamp Lighting 12 96% 15.49 $13.23 $ – $3.00 $0.50 $0.021 15.39 3.94 2
2010—T5 fluorescents 1- or 2-lamp 4' T5 fixture 1- or 2-lamp 4' T12 fixture
Fixture Lighting 11 96% 69.00 0.02 $54.44 $ – $20.19 $14.00 $0.021 3.38 2.44 1
2010—T5 fluorescents 3-lamp 4' T5 fixture 3-lamp 4' T12 fixture Fixture Lighting 11 96% 137.92 0.03 $108.82 $ – $40.37 $24.00 $0.021 3.88 2.45 1
2010—T5 fluorescents 4-lamp 4' T5 fixture 4-lamp 4' T12 fixture Fixture Lighting 11 96% 155.60 0.04 $122.77 $ – $53.82 $30.00 $0.021 3.54 2.10 1
2010—T5
fluorescents
2-lamp 4' T5 HO
fixture
4-lamp 4'
T12 fixture
Fixture Lighting 11 96% 155.60 0.04 $122.77 $ – $33.64 $28.00 $0.021 3.77 3.21 1
2010—T5 fluorescents 3-lamp 4' T5 HO fixture Fixture drawing 250 W or more
Fixture Lighting 11 96% 247.55 0.06 $195.32 $ – $50.46 $50.00 $0.021 3.40 3.37 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 99
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
2010—T5 fluorescents 4-lamp 4' T5 HO fixture Fixture drawing 400 W or more
Fixture Lighting 11 96% 565.83 0.13 $446.44 $ – $67.28 $90.00 $0.021 4.21 5.35 1
2010—T5 fluorescents 6-lamp 4' T5 HO fixture Fixture
drawing 400 W or more
Fixture Lighting 11 96% 318.28 0.08 $251.12 $ – $100.91 $60.00 $0.021 3.62 2.28 1
2010—Efficient Metal Halide (MH) Lighting
30-70 W efficient MH fixture Fixture drawing at least 20 W more
Fixture Lighting 16 96% 401.06 $443.29 $ – $400.00 $18.00 $0.021 16.11 1.08 2
2010—MH Lighting 70-150 W efficient MH fixture Fixture drawing at least 25 W more
Fixture Lighting 16 96% 275.28 $304.27 $ – $449.55 $22.00 $0.021 10.51 0.67 2, 3
2010—MH Lighting 150-250 W efficient MH fixture Fixture drawing at least 40 W more
Fixture Lighting 16 96% 250.90 $277.32 $ – $400.00 $26.00 $0.021 8.51 0.68 2, 3
2010—MH Lighting 250-360 W efficient MH fixture Fixture drawing at least 80 W more
Fixture Lighting 16 96% 370.31 $409.31 $ – $361.14 $55.00 $0.021 6.26 1.10 2
2010—MH Lighting 360-500 W efficient MH fixture Fixture drawing at least 120 W more
Fixture Lighting 16 96% 358.00 $395.70 $ – $361.14 $75.00 $0.021 4.60 1.06 2
2010—MH Lighting 500 W+ efficient MH fixture Fixture drawing at least 200 W more
Fixture Lighting 16 96% 780.00 $862.14 $ – $419.29 $105.00 $0.021 6.82 1.96 2
2010—Lighting controls Occupancy sensor, wall or ceiling Manual light switch Sensor Lighting 8 96% 289.99 - $168.74 $ – $77.00 $40.00 $0.021 3.51 1.98 1
2010—Lighting controls Photocell dimming control No prior dimming control
Control Lighting 8 96% 238.71 - $138.90 $ – $60.00 $40.00 $0.021 2.96 2.08 1
2010—Lighting controls Central lighting control system Manual switches or no control
Square Feet Lighting 8 96% 0.82 - $0.48 $ – $0.30 $0.10 $0.021 3.90 1.48 1
2010—Lighting controls Auto-off time switch Controlling 100 W or more
Switch Lighting 8 96% 177.00 - $102.99 $ – $43.00 $20.00 $0.021 4.17 2.16 1
2010—Lighting controls Time clock control No prior control Control Lighting 8 96% 583.51 - $339.54 $ – $240.00 $20.00 $0.021 10.11 1.34 1

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 100 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
2010—Lighting controls Screw-in lamp (25 W or less) Fixture drawing 40 W or more
Lamp Lighting 12 96% 174.76 $149.30 $ – $15.63 $2.00 $0.021 25.28 7.64 2
2010— Compact
Fluorescents (CFL) or Light-Emitting Diodes (LED)
Larger wattage screw-in lamp Fixture
drawing 100 W or more
Lamp Lighting 12 96% 365.79 $312.49 $ – $17.00 $4.00 $0.021 25.68 12.42 2
2010—CFLs or LEDs CFL or LED hardwired fixture Incandescent or other fixture
Fixture Lighting 12 96% 379.66 $324.34 $ – $24.00 $15.00 $0.021 13.55 9.85 2
2010—Sign Llghting LED or equivalent exit sign Incandescent or Fluorescent exit sign
Fixture Lighting 16 96% 332.88 0.03 $367.93 $ – $51.00 $15.00 $0.021 16.06 6.25 1
2010—Sign lighting LED or equivalent sign lighting Marquee/Sign lighting Square Feet Lighting 16 96% 85.85 0.39 $94.89 $ – $18.00 $15.00 $0.021 5.42 4.63 1
Standard T8s 2-ft or 3-ft T8s and electronic ballast (one or more lamps)
2-ft or 3-ft T12 (includes U-bend)
Fixture Lighting 11 96% 105.00 $82.85 $ – $40.92 $8.00 $0.021 7.79 1.90 4
Standard T8s 1 Lamp 4-ft T8 and electronic ballast 1 Lamp 4-ft T12 Fixture Lighting 11 96% 73.50 $57.99 $ – $28.40 $12.00 $0.021 4.11 1.90 4
Standard T8s 1 or 2 Lamp 4-ft T8's and electronic ballasts 2 Lamp 4-ft T12 Fixture Lighting 11 96% 126.00 $99.41 $ – $37.60 $14.00 $0.021 5.73 2.43 4
Standard T8s 2 or 3 Lamp 4-ft T8's and electronic ballast 3 Lamp 4-ft T12 Fixture Lighting 11 96% 208.25 $164.31 $ – $54.45 $18.00 $0.021 7.05 2.75 4
Standard T8s 2, 3, or 4 Lamp 4-ft T8's and electronic ballasts
4 Lamp 4-ft T12 Fixture Lighting 11 96% 271.83 $214.48 $ – $59.83 $22.00 $0.021 7.43 3.22 4
Standard T8s 1 or 2 Lamp 6-ft T8's and electronic ballast 1 or 2 Lamp 6-ft T12
Fixture Lighting 12 96% 137.67 $117.61 $ – $49.33 $14.00 $0.021 6.68 2.22 4
Standard T8s 1 or 2 Lamp 6-ft T8's and electronic ballast (slimline & HO)
1 or 2 Lamp 6-ft T12HO/ VHO
Fixture Lighting 12 96% 385.23 $329.10 $ – $81.67 $14.00 $0.021 14.30 3.63 4
Standard T8s 1 or 2 Lamp 8-ft T8's and electronic ballast 1 or 2 Lamp 8-ft T12
Fixture Lighting 12 96% 138.83 $118.60 $ – $58.47 $12.00 $0.021 7.63 1.91 4
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 101
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Standard T8s 2, 3 or 4 Lamp 8-ft T8's and electronic ballast
3 or 4 Lamp 8-ft T12
Fixture Lighting 12 96% 334.60 $285.85 $ – $93.81 $24.00 $0.021 8.84 2.80 4
Standard T8s 1 or 2 Lamp 8-ft T8's
and electronic ballast (slimline & HO)
1 or 2
Lamp 8-ft T12HO/ VHO
Fixture Lighting 12 96% 509.37 $435.15 $ – $68.14 $12.00 $0.021 18.41 5.45 4
Standard T8s 2, 3 or 4 Lamp 8-ft T8's and electronic ballast (slimline & HO)
3 or 4 Lamp 8-ft T12HO/ VHO
Fixture Lighting 12 96% 1,237.54 $1,057.22 $ – $96.39 $24.00 $0.021 20.30 8.49 4
Standard T8s 2 or 4 Lamp 4-ft T8's and electronic ballast (tandem/retrofit)
1 or 2 Lamp 8-ft T12
Fixture Lighting 11 96% 143.50 $113.22 $ – $53.07 $22.00 $0.021 4.35 1.98 4
Standard T8s 2 or 4 Lamp 4-ft T8's
and electronic ballast (tandem/retrofit)
1 or 2
Lamp 8-ft T12HO/ VHO
Fixture Lighting 11 96% 528.50 $416.99 $ – $55.24 $30.00 $0.021 9.74 6.13 4
High-performance T8s 1 Lamp 4-ft HP T8 and electronic ballast 1 Lamp 4-ft T12 Fixture Lighting 11 96% 84.00 $66.28 $ – $44.94 $22.00 $0.021 2.68 1.39 4
High-performance T8s 1 or 2 Lamp 4-ft HP T8's and electronic ballast
2 Lamp 4-ft T12 Fixture Lighting 11 96% 125.30 $98.86 $ – $55.59 $24.00 $0.021 3.56 1.67 4
High-performance T8s 2 or 3 Lamp 4-ft HP T8's and electronic ballast
3 Lamp 4-ft T12 Fixture Lighting 11 96% 208.25 $164.31 $ – $70.35 $32.00 $0.021 4.34 2.16 4
High-performance T8s 2, 3, or 4 Lamp 4-ft HP T8's and electronic ballast
4 Lamp 4-ft T12 Fixture Lighting 11 96% 266.00 $209.88 $ – $74.86 $34.00 $0.021 5.09 2.56 4
High-performance T8s 2 or 4 Lamp 4-ft HP T8's and electronic ballast (tandem/retrofit)
1 or 2 Lamp 8-ft T12
Fixture Lighting 11 96% 167.13 $131.86 $ – $93.00 $34.00 $0.021 3.37 1.34 4
High-performance T8s 2 or 4 Lamp 4-ft HP
T8's and electronic ballast (tandem/retrofit)
1 or 2
Lamp 8-ft T12HO/ VHO
Fixture Lighting 11 96% 551.33 $435.00 $ – $106.53 $45.00 $0.021 7.38 3.61 4
T5 (Non-HO) 1 or 2 Lamp 4-ft T5's and electronic ballast 1 or 2 Lamp 4-ft T12
Fixture Lighting 11 96% 119.00 $93.89 $ – $50.30 $14.00 $0.021 5.46 1.76 4
T5 (Non-HO) 2, 3, or 4 Lamp 4-ft T5's and electronic ballast
3 or 4 Lamp 4-ft T12
Fixture Lighting 11 96% 229.25 $180.88 $ – $90.07 $24.00 $0.021 6.03 1.88 4

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 102 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
T5/T8 High bay (new fixture) 4 Lamp 4-ft T8s and electronic ballast Fixture (lamp & ballast) using ≥ 200 watts
Fixture Lighting 12 96% 532.49 $454.90 $ – $139.01 $75.00 $0.021 5.07 2.96 4
T5/T8 High bay (new fixture) 6 Lamp 4-ft T8s and
electronic ballast or 2, 3, or 4 Lamp 4-ft T5HO's and electronic ballast
Fixture
(lamp & ballast) using 200 to 399 watts
Fixture Lighting 12 96% 364.44 $311.34 $ – $173.68 $75.00 $0.021 3.62 1.68 4
T5/T8 High bay (new fixture) 6 or 8 Lamp 4-ft T8's and electronic ballast or 4 or 6 Lamp 4-ft T5HO's and electronic ballast
Fixture (lamp & ballast) using ≥ 400 watts
Fixture Lighting 12 96% 872.96 $745.76 $ – $222.90 $110.00 $0.021 5.58 3.02 4
T5/T8 High bay (new fixture) 10 or 12 Lamp 4-ft T8's and electronic ballast or 8 or 10 Lamp 4-ft T5HO's and electronic ballast
Fixture (lamp & ballast) 751 to 1100 watts
Fixture Lighting 12 96% 2,084.25 $1,780.55 $ – $375.60 $180.00 $0.021 7.64 4.15 4
Compact Fluorescents (CFLs)
Screw-in compact fluorescent ≤ 32 watts Fixture using ≥ 60 input watts
Fixture Lighting 12 96% 98.00 $83.72 $ – $23.00 $2.00 $0.021 19.81 3.32 4
CFLs Screw-in compact fluorescent 33 to 59
watts
Fixture using ≥
100 input watts
Fixture Lighting 12 96% 143.50 $122.59 $ – $31.00 $4.00 $0.021 16.78 3.57 4
CFLs Screw-in compact fluorescent ≥ 60 watts Fixture using ≥ 150 input watts
Fixture Lighting 12 96% 175.00 $149.50 $ – $29.00 $20.00 $0.021 6.06 4.44 4
CFLs Screw-in cold-cathode ≤ 32 watts Fixture using ≥ 60 input watts
Fixture Lighting 12 96% 164.50 $140.53 $ – $34.67 $4.00 $0.021 18.10 3.66 4
CFLs Hard-wired compact
fluorescent ≤ 49 watts and electronic ballasts
Fixture
using ≥ 90 input watts
Fixture Lighting 12 96% 143.50 $122.59 $ – $85.00 $30.00 $0.021 3.56 1.37 4
CFLs Hard-wired compact fluorescent 50 to 99 watts and electronic ballasts
Fixture using ≥ 150 input watts
Fixture Lighting 12 96% 178.50 $152.49 $ – $104.50 $40.00 $0.021 3.35 1.39 4
LEDs Screw-in or pin-based LED ≤ 10 watts Fixture using ≥ 40 input watts
Fixture Lighting 12 96% 105.00 $89.70 $ – $45.00 $10.00 $0.021 7.06 1.88 4

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 103
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Ceramic/pulse-start MH 150 to 250 input watts metal halide Fixture (lamp & ballast) using ≥ 295 input watts
Fixture Lighting 16 96% 570.50 $630.58 $ – $185.00 $30.00 $0.021 14.42 3.17 4
Ceramic/pulse-
start MH
251 to 360 input watts
metal halide
Fixture
(lamp & ballast) using ≥ 450 input watts
Fixture Lighting 16 96% 499.63 $552.24 $ – $217.50 $55.00 $0.021 8.09 2.39 4
Ceramic/pulse-start MH 361+ input watts metal halide Fixture (lamp & ballast)
using ≥ 600 input watts
Fixture Lighting 16 96% 2,033.50 $2,247.64 $ – $245.00 $105.00 $0.021 14.61 7.65 4
LED Exits LED exit sign or equivalent (5 watts or less)
Exit sign using ≥ 18 watts
Fixture Lighting 16 96% 88.67 $98.00 $ – $68.69 $25.00 $0.021 3.50 1.37 4
Lighting controls Wall switch occupancy sensor Manual or no prior control
Fixture Lighting 10 96% 149.30 $107.71 $ – $90.00 $35.00 $0.021 2.71 1.14 4
Lighting controls Wall or ceiling mount occupancy sensor Manual or no prior
control
Fixture Lighting 10 96% 472.17 $340.65 $ – $130.00 $50.00 $0.021 5.46 2.39 4
Lighting controls Fixture mount occupancy sensor Manual or no prior control
Fixture Lighting 10 96% 252.22 $181.96 $ – $100.00 $50.00 $0.021 3.16 1.69 4
Lighting controls Interior photocell control (dimming, step-dimming or switching)
Manual or no prior control
Fixture Lighting 10 96% 379.42 $273.73 $ – $130.00 $40.00 $0.021 5.48 1.96 4
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 $196.77 $ – $125.00 $40.00 $0.021 4.13 1.48 4
A/C/Heat pump units PTAC/PTHP unit, min 12 EER Standard PTAC/PTHP unit
Unit HVAC 12 80% 562.50 $599.74 $ – $255.00 $50.00 $0.021 7.76 2.12 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 0.34 $308.19 $ – $50.00 $25.00 $0.021 8.21 4.93 5
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 0.40 $359.56 $ – $100.00 $50.00 $0.021 5.15 3.00 5
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 104 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
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 0.45 $404.50 $ – $150.00 $75.00 $0.021 3.97 2.29 5
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 $535.70 $ – $75.00 $50.00 $0.021 7.30 5.44 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 0.34 $308.19 $ – $75.00 $75.00 $0.021 3.08 3.08 5
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 0.40 $359.56 $ – $150.00 $100.00 $0.021 2.72 1.97 5
A/C/Heat pump units 6-10 ton A/C unit, min 11 EER Standard 6-10 ton AC unit
Ton HVAC 15 80% 120.09 0.17 $154.83 $ – $100.00 $50.00 $0.021 2.36 1.34 5
A/C/Heat pump units 11-19 ton A/C unit, min 10.8 EER Standard 11-19 ton AC unit
Ton HVAC 15 80% 124.95 0.18 $161.09 $ – $100.00 $50.00 $0.021 2.45 1.39 5
A/C/Heat pump units 20 ton or more A/C unit, min 10 EER Standard 20 ton+ AC unit
Ton HVAC 15 80% 92.96 0.13 $119.85 $ – $75.00 $50.00 $0.021 1.85 1.33 5
Economizers Air-side economizer control addition No prior control Ton HVAC 15 80% 300.00 0.11 $386.79 $ – $170.00 $75.00 $0.021 3.81 1.97 5
Economizers Water-side economizer control addition
No prior control Ton HVAC 10 80% 1,199.10 0.06 $1,088.80 $ – $463.00 $75.00 $0.021 8.69 2.12 5
Economizers Air-side economizer system repair Non-functional Economizer
Unit HVAC 15 80% 4,499.29 1.72 $5,800.88 $ – $630.00 $250.00 $0.021 13.47 7.16 5
Evaporative coolers/pre-coolers
Pre-cooler added to condenser Standard air cooled AC unit
Ton HVAC 10 80% 832.30 0.78 $755.74 $ – $200.00 $100.00 $0.021 5.15 3.06 5
Evaporative coolers/pre-coolers
Retrofit to direct evaporative cooler Replacing standard AC unit
Ton HVAC 15 80% 902.52 0.95 $1,163.61 $ – $400.00 $200.00 $0.021 4.25 2.46 5
Evaporative
coolers/pre-coolers
Retrofit to indirect evaporative cooler Replacing
standard AC unit
Ton HVAC 15 80% 676.89 0.71 $872.71 $ – $550.00 $300.00 $0.021 2.22 1.36 5
Variable speed fans/pumps Variable speed drive, fan Single speed HVAC system fan
HP HVAC 15 96% 1,078.29 - $1,390.23 $ – $187.00 $60.00 $0.021 16.15 6.52 5

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 105
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Variable speed fans/pumps Variable speed drive, pump Single-speed HVAC system pump
HP HVAC 15 96% 891.74 - $1,149.72 $ – $187.00 $60.00 $0.021 14.02 5.50 5
Programmable Thermostats 7-day, 2-stage setback thermostat Manual thermostat Unit HVAC 11 80% 4,209.94 - $4,161.81 $ – $174.76 $40.00 $0.021 25.93 14.09 5
Automated control systems Energy management control systems Manual controls ft2 HVAC 14 80% 1.20 - $1.46 $ – $0.95 $0.30 $0.021 3.59 1.38 5
Automated control systems Control system reprogramming/ optimization
Automated control system
ft2 HVAC 4 80% 0.75 $0.28 $ – $0.15 $0.10 $0.021 1.93 1.43 2
Automated control systems Lodging room occupancy control system
Manual controls Room HVAC 12 80% 900.00 $959.58 $ – $75.00 $50.00 $0.021 11.14 8.64 2
NEMA Premium®
Efficiency Motors
1 hp Motor, min 85.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 57.25 0.02 $66.49 $ – $50.00 $20.00 $0.021 3.01 1.28 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 0.02 $82.91 $ – $73.00 $25.00 $0.021 3.00 1.10 5
NEMA Premium
Efficiency Motors
2 hp Motor, min 86.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 94.86 0.03 $110.18 $ – $65.00 $30.00 $0.021 3.31 1.61 5
NEMA Premium
Efficiency Motors
3 hp Motor, min 89.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 145.98 0.05 $169.55 $ – $73.00 $35.00 $0.021 4.28 2.18 5
NEMA Premium
Efficiency Motors
5 hp Motor, min 89.5% efficiency Same or larger hp standard motor
Motor Motor 15 96% 182.82 0.06 $212.33 $ – $99.00 $40.00 $0.021 4.65 2.03 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 0.13 $514.91 $ – $71.00 $55.00 $0.021 7.69 6.20 5
NEMA Premium
Efficiency Motors
10 hp Motor, min 91.7% efficiency Same or larger hp standard motor
Motor Motor 15 96% 544.74 0.16 $632.69 $ – $90.00 $70.00 $0.021 7.46 6.04 5
NEMA Premium
Efficiency Motors
15 hp Motor, min 93.0% efficiency Same or larger hp standard motor
Motor Motor 15 96% 720.26 0.21 $836.55 $ – $168.00 $90.00 $0.021 7.64 4.46 5
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 106 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
NEMA Premium
Efficiency Motors
20 hp Motor, min 93.0% efficiency Same or larger hp standard motor
Motor Motor 15 96% 996.47 0.30 $1,157.36 $ – $165.00 $110.00 $0.021 8.49 6.05 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 0.42 $1,863.34 $ – $329.00 $130.00 $0.021 10.93 5.04 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 0.48 $2,112.68 $ – $331.00 $150.00 $0.021 10.78 5.60 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 0.54 $2,379.75 $ – $398.00 $180.00 $0.021 10.24 5.28 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 0.56 $2,462.46 $ – $384.00 $220.00 $0.021 8.94 5.60 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 0.60 $3,404.64 $ – $332.00 $280.00 $0.021 9.57 8.35 5
NEMA Premium
Efficiency Motors
75 hp Motor, min 95.4% efficiency Same or larger hp standard motor
Motor Motor 15 96% 3,007.97 0.62 $3,493.62 $ – $366.00 $350.00 $0.021 8.12 7.83 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 0.91 $5,180.16 $ – $555.00 $420.00 $0.021 9.68 7.73 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 1.24 $7,466.34 $ – $961.00 $550.00 $0.021 10.46 6.64 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 1.40 $8,401.52 $ – $609.00 $650.00 $0.021 10.06 10.58 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 1.95 $11,704.27 $ – $964.00 $750.00 $0.021 11.68 9.63 5
Downsizing bonus Downsizing motors during retrofit 10-200 hp
existing motor
HP Motor 15 96% 12.60 0.00 $14.64 $ – $- $3.00 $0.021 4.30 4.30 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 107
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
ECM motors ECM motor Standard induction motor
Motor Motor 15 96% 421.80 0.08 $489.90 $ – $110.00 $30.00 $0.021 12.10 4.07 5
Variable speed controls Variable speed drives Standard
motor, 5-200 hp
HP Motor 10 96% 3,542.00 - $2,870.99 $ – $187.00 $60.00 $0.021 20.51 10.75 5
Premium windows SHGC of .30 or less and U-Factor .30 or less.
Standard window ft2 HVAC 30 80% 1.38 0.00 $2.87 $ – $1.50 $1.50 $0.021 1.50 1.50 5
Efficient windows SHGC of .40 or less and U-Factor .42 or less.
Standard window ft2 HVAC 30 80% 0.92 0.00 $1.91 $ – $0.68 $1.00 $0.021 1.50 2.00 5
Window shading Adding window shade screen No screen or other shading
ft2 HVAC 10 80% 2.10 0.00 $1.91 $ – $1.00 $0.50 $0.021 2.80 1.62 5
2010—Roll-up doors Insulated door (min R4) Uninsulated roll-up door ft2 Miscellaneous 8 80% 0.30 $0.17 $ – $0.08 $0.05 $0.021 2.45 1.81 2,6
Reflective roofing Adding reflective roof treatment Non-reflective low pitch roof
ft2 HVAC 15 80% 0.40 0.00 $0.52 $ – $0.32 $0.05 $0.021 7.06 1.50 5
Roof/ceiling insulation Increasing to R24 min insulation Insulation level, R11 or less
ft2 HVAC 40 80% 0.92 0.00 $2.20 $ – $0.83 $0.10 $0.021 14.73 2.50 5
Roof/ceiling insulation Increasing to R38 min insulation Insulation level, R11 or less
ft2 HVAC 40 80% 1.46 0.00 $3.48 $ – $0.95 $0.20 $0.021 12.07 3.34 5
Wall insulation Increase to R11 min insulation Insulation level, R5 or less
ft2 HVAC 40 80% 1.04 0.00 $2.49 $ – $0.62 $0.05 $0.021 27.73 3.81 5
Wall insulation Increase to R19 min insulation Insulation level, R5 or less
ft2 HVAC 40 80% 2.44 0.00 $5.82 $ – $0.74 $0.10 $0.021 30.78 7.01 5
Refrigeration cases Efficient, medium-temp open case Standard medium-temp open case
Linear Foot Refrigeration 16 96% 148.18 0.01 $154.48 $ – $100.00 $20.00 $0.021 6.42 1.48 5
Refrigeration cases Efficient, medium-temp reach-in Standard medium-temp open case
Linear Foot Refrigeration 16 96% 564.94 0.06 $588.92 $ – $100.00 $100.00 $0.021 5.05 5.05 5
Refrigeration cases Efficient, low-temp reach-in (reach-in) Standard low-temp reach-in
Linear Foot Refrigeration 16 96% 478.36 0.04 $498.67 $ – $100.00 $150.00 $0.021 2.99 4.27 5
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 108 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Refrigeration cases Efficient, low-temp reach-in (open case) Standard low-temp open case
Linear Ft Refrigeration 16 96% 1,208.00 0.12 $1,259.29 $ – $100.00 $150.00 $0.021 6.89 9.49 5
Refrigeration cases Efficient, low-temp reach-in (coffin case) Standard
low-temp coffin case
Linear Ft Refrigeration 16 96% 703.42 0.07 $733.29 $ – $100.00 $55.00 $0.021 10.09 6.23 5
Refrigeration cases Vertical night covers No covers present Linear Ft Refrigeration 5 96% 148.00 - $49.83 $ – $9.00 $9.00 $0.021 3.95 3.95 5
Refrigeration cases Horizontal night covers No covers present Linear Ft Refrigeration 5 96% 59.00 - $19.87 $ – $9.00 $5.00 $0.021 3.06 1.89 5
Refrigeration cases Refrigeration line insulation No insulation present
Linear Ft Refrigeration 11 96% 17.00 0.00 $12.59 $ – $2.00 $1.00 $0.021 8.90 5.21 5
Refrigeration cases Door gasket—walk-in No or damaged door gasket
Linear Ft Refrigeration 4 96% 137.50 0.02 $36.39 $ – $4.00 $2.00 $0.021 7.15 5.13 5
Refrigeration cases Door gasket—reach-in Damaged door gasket
Linear Ft Refrigeration 4 96% 92.50 0.01 $24.48 $ – $4.00 $1.00 $0.021 7.99 4.04 5
Refrigeration cases Auto-closer—walk-in No or damaged auto closer, low-temp
Unit Refrigeration 8 96% 2,470.00 0.40 $1,342.80 $ – $433.00 $50.00 $0.021 12.65 2.75 5
Refrigeration cases Auto-closer—reach-in Damaged auto closer, low-temp
Unit Refrigeration 8 96% 1,297.00 0.18 $705.11 $ – $300.00 $50.00 $0.021 8.76 2.13 5
Refrigeration cases Auto-closer—walk-in No or damaged auto closer, med-temp
Unit Refrigeration 8 96% 1,067.00 0.17 $580.07 $ – $433.00 $40.00 $0.021 8.92 1.27 5
Refrigeration cases Auto-closer—reach-in Damaged
auto closer, med-temp
Unit Refrigeration 8 96% 243.00 0.03 $132.11 $ – $125.00 $40.00 $0.021 2.81 1.00 5
Refrigeration cases No-heat glass doors Standard low-temp reach-in
Unit Refrigeration 12 96% 749.00 0.02 $601.08 $ – $200.00 $50.00 $0.021 8.78 2.75 5
2011—Refrigeration cases
Anti-sweat heat (ASH) controls Low or med-temp case w/out controls
Linear Ft Refrigeration 8 96% 379.00 $206.04 $ – $40.00 $40.00 $0.021 4.12 4.12 7

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 109
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
2010—Refrigeration cases
ASH controls Low or med-temp case w/out controls
Linear Foot Refrigeration 12 96% 216.00 0.01 $173.34 $ – $56.00 $20.00 $0.021 6.78 2.82 5
Vending machines ENERGY STAR® vending machine Standard
vending machine
Unit Miscellaneous 14 96% 1,472.00 0.13 $1,432.23 $ – $350.00 $75.00 $0.021 12.98 3.72 5
Vending machines Beverage machine control Vending machine with no sensor
Unit Miscellaneous 14 96% 546.50 - $531.73 $ – $170.00 $75.00 $0.021 5.90 2.87 5
Vending machines Other cold product control Vending machine with no sensor
Unit Miscellaneous 14 96% 546.50 - $531.73 $ – $170.00 $50.00 $0.021 8.30 2.89 5
Vending machines Non-cooled snack control Vending machine with no sensor
Unit Miscellaneous 14 96% 382.55 - $372.21 $ – $170.00 $25.00 $0.021 10.82 2.07 5
Commercial kitchen equipment
ENERGY STAR dishwasher Standard dishwasher Unit Miscellaneous 11 96% 231.00 0.07 $180.27 $ – $55.00 $15.00 $0.021 8.72 2.97 5
Commercial kitchen equipment
Low-temperature dish machine Dish machine w/ electric booster
kW Office 13 96% 657.86 0.07 $589.01 $ – $127.00 $75.00 $0.021 6.37 4.08 5
Commercial kitchen equipment
ENERGY STAR refrigerator Standard refrigerator Refrigerator Miscellaneous 13 96% 85.71 0.01 $78.00 $ – $30.00 $30.00 $0.021 2.35 2.35 5
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Refrigerator—Less than 30 cu.ft.
Solid or Glass Door Refrigerator—Less than 30 cu.ft.
Refrigerator Refrigeration 12 96% 379.75 $304.75 $ – $226.17 $75.00 $0.021 3.53 1.28 8
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Refrigerator—30 to 49.9 cu.ft
Solid or Glass Door Refrigerator—30 to 49.9 cu.ft
Refrigerator Refrigeration 12 96% 407.00 $326.62 $ – $226.17 $90.00 $0.021 3.18 1.37 8

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 110 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Refrigerator—50 cu.ft. and greater
Solid or Glass Door Refrigerator—50 cu.ft. and greater
Refrigerator Refrigeration 12 96% 541.00 $434.16 $ – $226.17 $140.00 $0.021 2.75 1.78 8
Commercial
kitchen equipment
ENERGY STAR 2.0
Solid or Glass Door Freezer—Less than 15 cu.ft.
Solid or
Glass Door Freezer—Less than 15 cu.ft.
Freezer Refrigeration 12 96% 1,532.50 $1,229.84 $ – $394.79 $100.00 $0.021 8.93 2.84 8
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Freezer—15 to 29.9 cu.ft.
Solid or Glass Door Freezer—15 to 29.9 cu.ft.
Freezer Refrigeration 12 96% 1,610.50 $1,292.44 $ – $394.79 $150.00 $0.021 6.75 2.96 8
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Freezer—30 to 49.9 cu.ft
Solid or Glass Door Freezer—30 to 49.9 cu.ft
Freezer Refrigeration 12 96% 1,992.50 $1,599.00 $ – $394.79 $175.00 $0.021 7.08 3.59 8
Commercial kitchen equipment
ENERGY STAR 2.0 Solid or Glass Door Freezer—50 cu.ft. and greater
Solid or Glass Door Freezer—50 cu.ft. and greater
Freezer Refrigeration 12 96% 3,978.50 $3,192.78 $ – $394.79 $200.00 $0.021 10.81 6.51 8
2010—
Commercial kitchen equipment
Solid door refrigerator,
2 doors
Commercial
2 door refrigerator
Refrigerator Refrigeration 12 96% 428.00 $343.47 $ – $111.00 $90.00 $0.021 3.33 2.77 9
2010—Commercial kitchen equipment
Solid door freezer, 2 doors Commercial 2 door freezer
Unit Refrigeration 12 96% 1,172.00 $940.54 $ – $363.00 $150.00 $0.021 5.17 2.38 9
Commercial kitchen equipment
Ice maker, up to 200 lbs/day Standard ice maker of the same size
Unit Miscellaneous 10 96% 161.20 $115.00 $ – $- $100.00 $0.021 1.07 1.07 10
Commercial kitchen equipment
Ice maker, more than 200 lbs/day Standard ice maker of the same size
Unit Miscellaneous 10 96% 596.33 $425.43 $ – $- $200.00 $0.021 1.92 1.92 11
Evaporator fans Evaporator fan controls Med-temp walk-in with no controls
Unit Refrigeration 5 96% 361.00 0.01 $121.55 $ – $85.00 $25.00 $0.021 3.58 1.29 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 111
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Evaporator fans Efficient evaporator fan motors Med- or low-temp walk-in
Motor Refrigeration 10 96% 478.30 0.05 $323.35 $ – $161.00 $100.00 $0.021 2.82 1.84 5
Evaporator fans ECM case fan motors Standard,
shaded-pole fan motors
Motor Refrigeration 15 96% 453.00 $446.20 $ – $110.00 $60.00 $0.021 6.16 3.65 12
2010—Evaporator fans ECM case fan motors Standard, shaded-pole fan motors
Motor Refrigeration 10 96% 673.00 0.09 $454.97 $ – $161.00 $30.00 $0.021 9.90 2.57 5
Compressors/ condensers Efficient, low-temp compressor Standard low-temp compressor
Ton Refrigeration 15 96% 1,051.00 0.16 $1,035.22 $ – $132.00 $45.00 $0.021 14.82 6.60 5
Compressors/ condensers Efficient, air-cooled condenser Standard
air cooled condenser
Ton Refrigeration 15 96% 410.01 0.10 $403.86 $ – $140.30 $100.00 $0.021 3.57 2.63 5
Compressors/ condensers Efficient, water-cooled condenser Standard air cooled condenser
Ton Refrigeration 15 96% 559.03 0.14 $550.63 $ – $209.00 $100.00 $0.021 4.73 2.44 5
Compressors/ condensers Efficient, evaporative, condenser Standard air cooled condenser
Ton Refrigeration 15 96% 678.74 0.17 $668.55 $ – $278.00 $200.00 $0.021 3.00 2.22 5
Head/suction pressure Floating head pressure controller Standard head pressure
control
HP Refrigeration 16 96% 1,916.94 0.07 $1,998.33 $ – $65.67 $60.00 $0.021 19.14 18.15 5
Head/suction pressure Floating suction pressure Standard suction pressure control
HP Refrigeration 16 96% 272.91 0.04 $284.50 $ – $52.48 $10.00 $0.021 17.36 4.83 5
Case/Walk-in Lighting T8 fluorescent lighting T12 or T10 fluorescent lighting
Lamp Refrigeration 6 96% 309.31 0.03 $125.87 $ – $44.70 $15.00 $0.021 5.62 2.42 5
Case/walk-in lighting LED display case lighting T12 or T10
fluorescent lighting
Linear Foot Refrigeration 6 96% 114.25 $46.49 $ – $39.76 $15.00 $0.021 2.57 1.08 13
Case/walk-in lighting Fluorescent walk-in light fixture Incandescent walk-in light fixture
Fixture Refrigeration 6 96% 627.99 0.08 $255.56 $ – $47.49 $25.00 $0.021 6.42 4.10 5
Office equipment 80 Plus® PC-desktop Standard personal computer
Unit Office 4 96% 542.32 0.06 $149.92 $ – $15.00 $5.00 $0.021 8.78 5.54 5

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 112 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin Cost
($/kWh)g UC Ratioh TRC Ratioi Source
Office equipment 80 Plus PC-server Standard personal computer, server
Unit Office 4 96% 542.32 0.06 $149.92 $ – $15.00 $10.00 $0.021 6.73 5.50 5
Office equipment ENERGY STAR PC Standard
personal computer
Unit Office 4 96% 457.32 0.05 $126.43 $ – $10.00 $10.00 $0.021 6.19 6.19 5
Office equipment ENERGY STAR Copier Standard copier w/o idle/off
Unit Office 6 96% 205.40 0.02 $87.03 $ – $40.00 $25.00 $0.021 2.85 1.91 5
Office equipment PC network power management No central control Unit Office 4 96% 99.00 $27.37 $ – $12.00 $10.00 $0.021 2.18 1.88 14
2010—Office equipment PC network power management No central control Unit Office 10 96% 196.00 0.01 $137.44 $ – $18.55 $10.00 $0.021 9.35 5.91 5
2010—Office equipment Flat panel LCD display Standard Cathode Ray (CRT) display
Unit Office 4 96% 233.79 0.03 $64.63 $ – $150.00 $10.00 $0.021 4.16 0.42 5, 15
Laundry machines High-efficiency washer Standard washer, electric hot water
Washer Miscellaneous 14 96% 287.00 0.06 $279.25 $ – $195.00 $25.00 $0.021 8.64 1.38 5
2010—Laundry machines High-efficiency, coin-op washer Coin-op washer, w/out electric hot
Washer Miscellaneous 8 96% 272.00 0.06 $156.44 $ – $175.00 $25.00 $0.021 4.89 0.86 5, 15
Laundry machines High-efficiency, coin-op washer Coin-op washer, electric hot water
Washer Miscellaneous 8 96% 434.00 0.10 $249.61 $ – $175.00 $200.00 $0.021 1.15 1.29 5
a Average measure life.
b 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses. e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009. Adjustment made in 2011 with Lighting Calculator.
2 Savings and participant costs calculated from Idaho Power engineering estimates and research. Participant costs include total install cost of the measure.
3 Measure not cost-effective due to participant cost. Adjustment made in 2011 with Lighting Calculator.
4 Evergreen Consulting Group, LLC. Idaho Power Lighting Tool. 2010.
5 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009.
6 Removed from program in 2011 and moved to Custom Efficiency.
7 RTF. Deemed MeasuresV14.xls. Averaged low and med temp. 2007.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 113
8 RTF. CommRefrigFreezerFY10v2_5.xls. Averaged solid and glass door. 2010. 9 RTF. CommRefrigFreezerFY10v2_4.xls. 2010.
10 RTF. ComIceMakerFY10v1_0.xls. Average of all ENERGY STAR air-cooled models producing less than 200 lbs/day. 2011.
11 RTF. ComIceMakerFY10v1_0.xls. Average of all ENERGY STAR air cooled models producing between 200-1000 lbs/day. 2011.
12 RTF. Grocery_DisplayCaseECMs_FY10v2_0.xls. 2010.
13 RTF. Grocery_DisplayCaseLEDs_FY10v2_0.xls and GroceryOpenDisplayCaseLEDs_v1.xls. Averaged the measures for less than 4 W/ln ft and 4-8.5 W/ln ft. 2011.
14 RTF. NonResNetCompPwrMgt_v3_0.xlsm. 2011.
15 Measure not cost-effective. Removed from program in 2011.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 114 Demand-Side Management 2011 Annual Report
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Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 115
Irrigation Efficiency
Segment: Irrigation
2011 Program Results
Cost Inputs Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................... $ 296,201 Test Benefit Cost Ratio
Program Incentives ............................................................. 2,064,103 I Utility Cost Test ................................... $ 11,123,018 $ 2,360,304 4.71
Total Utility Cost ................................................................. $ 2,360,304 P Total Resource Cost Test ................... 20,549,264 13,281,492 1.55
Ratepayer Impact Measure Test ......... 11,123,018 7,004,145 1.59
Measure Equipment and Installation
(Incremental Participant Cost) .............................................. $ 12,985,291 M Participant Cost Test ........................... 16,134,190 12,985,291 1.24

Net Benefit Inputs Ref
Resource Savings
2011 Annual Gross Energy (kWh) ................. 13,979,833 Benefits and Costs Included in Each Test
NPV Cumulative Energy (kWh) ..................... 102,337,497 $ 11,123,018 Utility Cost Test ........................................ = S * NTG = P
Total Electric Savings .................................... $ 11,123,018 S Total Resource Cost Test ......................... = (S * NTG) + NUI + NEB = P +((M—I) * NTG)
Ratepayer Impact Measure Test .............. = S * NTG = P + (B * NTG)
Participant Bill Savings Participant Cost Test ................................ = B + I + NUI + NEB = M
NPV Cumulative Participant Savings............. $ 4,643,841 B
Assumptions for Levelized Calculations
Other Benefits Discount Rate
Non-Utility Rebates/Incentives .......................................... $ — NUI Nominal (Weighted Average Cost of Capital [WACC]) ................................. 7.00%
Non-Electric Benefits ........................................................ $ 9,426,246 NEB Real ((1 + WACC) / (1 + Escalation))—1 ...................................................... 3.88%
Escalation Rate ................................................................................................. 3.00%
Net-to-Gross (NTG) ........................................................................................... 100%
Average 2011 Customer Segment Rate/kWh .................................................... $0.048
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. 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 116 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Irrigation Efficiency Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name a Measure Description Replacing Measure Unit End Use
Measure
Life (years)b NTGc
Annual Gross
Energy Savings (kWh/yr)d
Peak
Demand Reduction (kW)e
NPV
Avoided Costsf
Non-
Electric Benefit
Gross
Incremental Participant Costg Incentive/ Unit
Admin
($/kWh)h UC Ratioi TRC Ratioj 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 $11.25 $ – $5.67 $1.50 $0.021 5.28 1.79 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 5 100% 39.00 $14.62 $ – $1.60 $0.25 $0.021 13.68 6.06 1
Sprinklers Rebuilt or new brass impact sprinklers
Unit Irrigation 5 100% 30.00 $14.16 $ – $12.33 $2.75 $0.021 4.19 1.09 1
Levelers Rebuilt or new wheel
line levelers
Unit Irrigation 5 100% 2.00 $0.94 $ – $3.25 $0.75 $0.021 1.19 0.29 1, 2
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 $13.21 $ – $11.88 $2.75 $0.021 3.96 1.06 1
Regulator replacement New low pressure regulators
Unit Irrigation 5 100% 38.00 $17.93 $ – $6.13 $5.00 $0.021 3.09 2.59 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 117
Benefit Cost Benefit/Cost Tests
Measure Name a Measure Description Replacing Measure Unit End Use
Measure
Life (years)b NTGc
Annual Gross
Energy Savings (kWh/yr)d
Peak
Demand Reduction (kW)e
NPV
Avoided Costsf
Non-
Electric Benefit
Gross
Incremental Participant Costg Incentive/ Unit
Admin
($/kWh)h UC Ratioi TRC Ratioj Source
Gasket replacement New drains, risercaps, and gaskets for hand lines, wheel lines or portable mainline
Unit Irrigation 5 100% 24.00 $11.33 $ – $8.80 $1.00 $0.021 7.53 1.22 1
Hub replacement New wheel line hubs Unit Irrigation 10 100% 69.00 $63.30 $ – $50.00 $12.00 $0.021 4.71 1.23 1
New goose necks New goose neck with drop tube or boomback
Outlet Irrigation 10 100% 14.00 $12.84 $ – $10.67 $1.00 $0.021 9.93 1.17 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 $35.84 $ – $18.00 $8.00 $0.021 3.98 1.89 1
Gasket replacement New center pivot base boot gasket
Unit Irrigation 8 100% 1,282.00 $957.34 $ – $250.00 $125.00 $0.021 6.30 3.46 1
a Available measures in the Irrigation Efficiency Menu Incentive Option. For the Custom Incentive Option, projects are thoroughly reviewed by Idaho Power staff.
b Average measure life. c 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 Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
f Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
g Incremental participant cost prior to customer incentive.
h Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals.
i Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
j Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((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 will be updated in 2012 to remove new wheel line levelers. Will be reviewed in 2012 as part of the University of Idaho research project.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 118 Demand-Side Management 2011 Annual Report
Year: 2011 Program: Irrigation Efficiency–Green Motors Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 25HP
Green Motors Program Rewind: motor size 25HP
Standard rewind practice
Motor Irrigation 20 80% 236.66 $383.93 $ – $176.33 $50.00 $0.050 4.97 1.89 1
Green Motors Program Rewind: motor size 30HP
Green Motors Program Rewind: motor size 30HP
Standard rewind practice
Motor Irrigation 20 80% 254.32 $412.59 $ – $193.67 $60.00 $0.050 4.54 1.84 1
Green
Motors Program Rewind: motor size 40HP
Green
Motors Program Rewind: motor size 40HP
Standard
rewind practice
Motor Irrigation 20 80% 297.31 $482.33 $ – $236.67 $80.00 $0.050 4.07 1.75 1
Green Motors Program Rewind: motor
size 50HP
Green Motors Program Rewind: motor size
50HP
Standard rewind practice
Motor Irrigation 20 80% 322.49 $523.18 $ – $262.00 $100.00 $0.050 3.60 1.70 1
Green Motors Program Rewind: motor size 60HP
Green Motors Program Rewind: motor size 60HP
Standard rewind practice
Motor Irrigation 20 80% 327.83 $531.84 $ – $309.00 $120.00 $0.050 3.12 1.48 1
Green Motors Program Rewind: motor size 70HP
Green Motors Program Rewind: motor size 70HP
Standard rewind practice
Motor Irrigation 20 80% 340.65 $552.65 $ – $334.00 $150.00 $0.050 2.65 1.41 1

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 119
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 100HP
Green Motors Program Rewind: motor size 100HP
Standard rewind practice
Motor Irrigation 20 80% 584.85 $948.81 $ – $414.33 $200.00 $0.050 3.31 1.89 1
Green Motors Program Rewind: motor size 125HP
Green Motors Program Rewind: motor size 125HP
Standard rewind practice
Motor Irrigation 20 80% 727.40 $1,180.07 $ – $465.33 $250.00 $0.050 3.30 2.06 1
Green
Motors Program Rewind: motor size 150HP
Green
Motors Program Rewind: motor size 150HP
Standard
rewind practice
Motor Irrigation 20 80% 866.82 $1,406.26 $ – $518.33 $300.00 $0.050 3.28 2.17 1
Green Motors Program Rewind: motor
size 200HP
Green Motors Program Rewind: motor size
200HP
Standard rewind practice
Motor Irrigation 20 80% 1,148.81 $1,863.74 $ – $624.00 $400.00 $0.050 3.26 2.34 1
Green Motors Program Rewind: motor size 250HP
Green Motors Program Rewind: motor size 250HP
Standard rewind practice
Motor Irrigation 20 80% 1,434.01 $2,326.41 $ – $802.00 $500.00 $0.050 3.26 2.29 1
Green Motors Program Rewind: motor size 300HP
Green Motors Program Rewind: motor size 300HP
Standard rewind practice
Motor Irrigation 20 80% 1,718.37 $2,787.74 $ – $810.67 $600.00 $0.050 3.25 2.61 1
Green Motors Program Rewind: motor size 350HP
Green Motors Program Rewind: motor size 350HP
Standard rewind practice
Motor Irrigation 20 80% 2,004.77 $3,252.36 $ – $849.67 $700.00 $0.050 3.25 2.83 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 120 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 400HP
Green Motors Program Rewind: motor size 400HP
Standard rewind practice
Motor Irrigation 20 80% 2,284.73 $3,706.56 $ – $949.00 $800.00 $0.050 3.24 2.87 1
Green Motors Program Rewind: motor size 450HP
Green Motors Program Rewind: motor size 450HP
Standard rewind practice
Motor Irrigation 20 80% 2,563.19 $4,158.29 $ – $1,037.33 $900.00 $0.050 3.24 2.92 1
Green
Motors Program Rewind: motor size 500HP
Green
Motors Program Rewind: motor size 500HP
Standard
rewind practice
Motor Irrigation 20 80% 2,847.99 $4,620.33 $ – $1,120.67 $1,000.00 $0.050 3.24 2.98 1
Green Motors Program Rewind: motor
size 600HP
Green Motors Program Rewind: motor size
600HP
Standard rewind practice
Motor Irrigation 20 80% 3,417.54 $5,544.32 $ – $1,651.45 $1,200.00 $0.050 3.24 2.56 1
Green Motors Program Rewind: motor size 700HP
Green Motors Program Rewind: motor size 700HP
Standard rewind practice
Motor Irrigation 20 80% 3,987.13 $6,468.37 $ – $1,801.73 $1,400.00 $0.050 3.24 2.69 1
Green Motors Program Rewind: motor size 800HP
Green Motors Program Rewind: motor size 800HP
Standard rewind practice
Motor Irrigation 20 80% 4,556.72 $7,392.43 $ – $1,999.06 $1,600.00 $0.050 3.24 2.75 1
Green Motors Program Rewind: motor size 900HP
Green Motors Program Rewind: motor size 900HP
Standard rewind practice
Motor Irrigation 20 80% 5,126.31 $8,316.48 $ – $2,203.88 $1,800.00 $0.050 3.24 2.80 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2011 Annual Report Page 121
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 1000HP
Green Motors Program Rewind: motor size 1000HP
Standard rewind practice
Motor Irrigation 20 80% 5,695.90 $9,240.53 $ – $2,375.10 $2,000.00 $0.050 3.24 2.86 1
Green Motors Program Rewind: motor size 1250HP
Green Motors Program Rewind: motor size 1250HP
Standard rewind practice
Motor Irrigation 20 80% 7,119.87 $11,550.67 $ – $2,837.23 $2,500.00 $0.050 3.24 2.96 1
Green
Motors Program Rewind: motor size 1500HP
Green
Motors Program Rewind: motor size 1500HP
Standard
rewind practice
Motor Irrigation 20 80% 8,543.85 $13,860.80 $ – $3,250.13 $3,000.00 $0.050 3.24 3.06 1
Green Motors Program Rewind: motor
size 1750HP
Green Motors Program Rewind: motor size
1750HP
Standard rewind practice
Motor Irrigation 20 80% 9,967.82 $16,170.93 $ – $3,709.54 $3,500.00 $0.050 3.24 3.11 1
Green Motors Program Rewind: motor size 2000HP
Green Motors Program Rewind: motor size 2000HP
Standard rewind practice
Motor Irrigation 20 80% 11,391.80 $18,481.07 $ – $4,161.19 $4,000.00 $0.050 3.24 3.15 1
Green Motors Program Rewind: motor size 2250HP
Green Motors Program Rewind: motor size 2250HP
Standard rewind practice
Motor Irrigation 20 80% 12,815.77 $20,791.20 $ – $4,533.29 $4,500.00 $0.050 3.24 3.22 1
Green Motors Program Rewind: motor size 2500HP
Green Motors Program Rewind: motor size 2500HP
Standard rewind practice
Motor Irrigation 20 80% 14,239.75 $23,101.33 $ – $4,959.78 $5,000.00 $0.050 3.24 3.25 1,2
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 122 Demand-Side Management 2011 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Description Replacing Measure Unit End Use
Measure
Life (years)a NTGb
Annual Gross
Energy Savings (kWh/yr)c
Peak
Demand Reduction (kW)d
NPV
Avoided Costse
Non-
Electric Benefit
Gross
Incremental Participant Costf Incentive/ Unit
Admin
($/kWh)g UC Ratioh TRC Ratioi Source
Green Motors Program Rewind: motor size 3000HP
Green Motors Program Rewind: motor size 3000HP
Standard rewind practice
Motor Irrigation 20 80% 17,087.70 $27,721.60 $ – $5,798.90 $6,000.00 $0.050 3.24 3.31 1,2
Green Motors Program Rewind: motor size 3500HP
Green Motors Program Rewind: motor size 3500HP
Standard rewind practice
Motor Irrigation 20 80% 19,935.65 $32,341.87 $ – $6,408.05 $7,000.00 $0.050 3.24 3.44 1,2
Green
Motors Program Rewind: motor size 4000HP
Green
Motors Program Rewind: motor size 4000HP
Standard
rewind practice
Motor Irrigation 20 80% 22,783.60 $36,962.13 $ – $7,154.28 $8,000.00 $0.050 3.24 3.49 1,2
Green Motors Program Rewind: motor
size 4500HP
Green Motors Program Rewind: motor size
4500HP
Standard rewind practice
Motor Irrigation 20 80% 25,631.54 $41,582.40 $ – $7,710.11 $9,000.00 $0.050 3.24 3.60 1,2
Green Motors Program Rewind: motor size 5000HP
Green Motors Program Rewind: motor size 5000HP
Standard rewind practice
Motor Irrigation 20 80% 28,479.49 $46,202.67 $ – $8,230.18 $10,000.00 $0.050 3.24 3.69 1,2
a Average measure life. Adjusted measure life from RTF to match methodology used to calculate measure life for industrial motor rewinds. Capped at 20 years.
b NTG percentage.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Estimated peak demand reduction measured at the customer’s meter, excluding line losses.
e Sum of NPV of avoided costs. Based on end-use load shape, measure life, and savings, including line losses and alternative costs by pricing period as provided in the 2011 IRP.
f Incremental participant cost prior to customer incentive.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2011 actuals. h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs * NTG) + Non-Electric Benefit) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost – Incentives) * NTG)).
1 RTF. GreenMotorsRewind_Ag_FY10v1_2.xls. 2010.
2 Incentive greater than incremental cost. This is a regional initiative sponsored by the RTF and GMPG. Costs and savings deemed by RTF and incentives set by GMPG. No incentive paid on motors greater than 450hp in 2011.