20140317DSM 2013 Supplement 1.pdf

March 15, 2014
2013 ANNUAL REPORT
SUPPLEMENT 1:
Demand-Side Management
Cost-Effectiveness
Printed on recycled paper
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page i
TABLE OF CONTENTS
Table of Contents ......................................................................................................................................... i
List of Tables ............................................................................................................................................... i
Supplement 1: Cost-Effectiveness ...............................................................................................................1
Cost-Effectiveness .................................................................................................................................1
Methodology ....................................................................................................................................1
Assumptions .....................................................................................................................................2
Net-to-Gross .....................................................................................................................................4
Results ..............................................................................................................................................4
2013 DSM Detailed Expense by Program .............................................................................................7
Cost-Effectiveness Tables by Program ......................................................................................................13
FlexPeak Management ...................................................................................................................13
Ductless Heat Pump Pilot ..............................................................................................................15
Energy Efficient Lighting ..............................................................................................................17
Energy House Calls........................................................................................................................21
ENERY STAR® Homes Northwest ...............................................................................................25
Heating & Cooling Efficiency Program ........................................................................................27
Home Improvement Program ........................................................................................................31
Home Products Program ................................................................................................................47
Rebate Advantage ..........................................................................................................................51
See ya later, refrigerator® ...............................................................................................................55
Weatherization Assistance for Qualified Customers .....................................................................57
Weatherization Solutions for Eligible Customers..........................................................................59
Building Efficiency ........................................................................................................................61
Custom Efficiency .........................................................................................................................65
Easy Upgrades ...............................................................................................................................69
Irrigation Efficiency Rewards ........................................................................................................83

LIST OF TABLES
Table 1. 2013 non-cost-effective measures ........................................................................................6
Table 2. 2013 DSM detailed expenses by program (dollars) .............................................................7
Table 3. Cost-effectiveness summary by program...........................................................................11
Supplement 1: Cost-Effectiveness Idaho Power Company
Page ii Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 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. New energy efficiency and demand
response programs or measures are identified both as part of the Integrated Resource Plan (IRP) process
and through ongoing program development and research activities.1 All current and potential programs and measures are screened by sector to determine cost-effectiveness. From the cost-effective demand-side management (DSM) resources, a forecast is developed and used in the IRP to define the
resource potential of both energy efficiency and demand response.
Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power
performs a cost-effectiveness analysis to assess whether a specific potential program design will be cost-effective from the perspective of Idaho Power and its customers. Incorporated into these models are inputs from various sources to use the most current and reliable information available. When possible,
Idaho Power leverages the experiences of other utilities in the region, or throughout the country, to
identify specific program parameters. This is typically accomplished through discussions with other
utilities’ program managers and researchers. Idaho Power also uses electric industry research organizations, such as ESource, the Edison Electrical Institute (EEI), Consortium for Energy Efficiency (CEE), American Council for an Energy Efficient Economy (ACEEE), Advanced Load Control Alliance
(ALCA), and Association of Energy Service Professionals (AESP), to identify similar programs and
their results. Additionally, Idaho Power relies on the results of program impact evaluations and
recommendations from consultants. In 2013, Idaho Power contracted with ADM Associates, Inc. (ADM), The Johnson Consulting Group, Market Decisions Corporation, Opinion Dynamics Corporation (Opinion), and TRC Energy Services for program evaluations and research.
Idaho Power’s goal is to have all programs reach benefit/cost (B/C) ratios of 1.0 or greater for the total
resource cost (TRC) test, utility cost (UC) test, and participant cost test (PCT) at the program level and
the measure level where appropriate. An exception to the measure level cost-effectiveness is when there is an interaction between measures. Idaho Power may launch a pilot or a program to evaluate estimates or assumptions in the cost-effectiveness analysis. Following the implementation of a program,
cost-effectiveness analyses are reviewed as new inputs from actual program activity become available,
such as actual program expenses, savings, or participation levels. If measures or programs are
determined to be not cost-effective after implementation, the program or measures are re-examined, including input provided from the company’s Energy Efficiency Advisory Group (EEAG).
Methodology
For its cost-effectiveness methodology, Idaho Power relies on the Electric Power Research Institute
(EPRI) End Use Technical Assessment Guide (TAG); the California Standard Practice Manual and its
subsequent addendum, the National Action Plan for Energy Efficiency’s (NAPEE) Understanding
Cost-Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging

1 The IRP is a biannual process with the most recent plan submitted in 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 2 Demand-Side Management 2013 Annual Report
Issues for Policy-Makers; and the National Action Plan on Demand Response. Traditionally,
Idaho Power has primarily used the TRC test and the UC test to develop B/C ratios to determine the
cost-effectiveness of DSM programs. These tests are still used because, as defined in the TAG and California Standard Practice Manual, they are most similar to supply-side tests and provide a useful basis to compare demand-side and supply-side resources.
For energy efficiency programs, each program’s cost-effectiveness is reviewed annually from a one-year
perspective. The annual energy-savings benefit value is summed over the life of the measure or program
and is discounted to reflect 2013 dollars. The result of the one-year perspective is shown in Supplement 1: Cost-Effectiveness. Appendix 4 of the main Demand-Side Management 2013 Annual Report includes the program cost-effectiveness to-date by including the culmination of actual historic savings values and
expenses as well as the ongoing energy savings benefit over the life of the measures included in
a program.
The goal of demand response programs is to minimize or delay the need to build new supply-side
resources. Unlike energy efficiency programs, demand response programs must acquire and retain participants each year to maintain a level of demand reduction capacity for the company.
Demand response programs are expensive and generally have a higher initial investment than energy
efficiency programs. As such, demand response programs are analyzed over the program life where
historical program demand reduction and expenses are combined with forecasted program activity to
better compare the program to a supply-side resource. While cost-effectiveness is determined over the program life, it is also calculated for each individual year.
Because the 2013 IRP process indicated a lack of near-term capacity deficits, on December 21, 2012,
Idaho Power filed a proposal with the Idaho Public Utilities Commission (IPUC) to temporarily suspend
two of its demand response programs, A/C Cool Credit and Irrigation Peak Rewards, for 2013.
A settlement workshop was held in February 2013, with Idaho Power and interested stakeholders to discuss plans for the 2013 cycling season. The stipulation was filed on February 14, 2013.
FlexPeak Management was not included in the original filing due to the company’s contractual
obligation to EnerNOC, Inc. As part of the public workshops on Case No. IPC-E-13-14, Idaho Power
and other stakeholders agreed on a new methodology for valuing demand response. The settlement
agreement was approved in IPUC Order No. 32923 on November 12, 2013. The new methodology will be applied to the cost-effectiveness models for all demand response programs in 2014.
Assumptions
Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumptions
for various measures. These assumptions are routinely reviewed and updated as new information
becomes available. For many of the measures within Supplement 1: Cost-Effectiveness, savings, costs,
and load shapes were derived from either the Regional Technical Forum (RTF); the Demand-Side Management Potential Study conducted by Nexant, Inc., in 2009, or the Idaho Power Energy Efficiency Potential Study conducted by EnerNOC Utility Solutions Consulting Group in 2012. In 2013,
EnerNOC provided Idaho Power with updated end-use load shapes. Those updated load shapes have
been applied to each program and measure when applicable.
The RTF regularly reviews, evaluates, and recommends eligible energy efficiency measures and the estimated savings and costs associated with those measures. As the RTF updates these assumptions, Idaho Power, in turn, applies those assumptions to current program offerings and assesses the need to
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 3
make any program changes. Idaho Power staff participate in the RTF by attending the monthly meetings
and contributing to various sub-committees. Because cost data from the RTF information is in 2006
dollars, measures with costs from the RTF have been escalated by 15.035 percent in 2012. No 2013
inflator was available. This percentage is provided by the RTF at http://rtf.nwcouncil.org/measures/support/files/RTFStandardInformationWorkbook_v1_5.xlsx.
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. In 2013, ADM Associates began developing a technical reference manual (TRM) for the Building Efficiency and Easy Upgrades programs. Once the TRM is
finalized in 2014, the measures will be reviewed and analyzed for cost-effectiveness. Occasionally,
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. The 2013 IRP was acknowledged by the IPUC in Order
No. 32980 on February 24, 2014. The 2013 IRP will be the source of all financial inputs in
cost-effectiveness models in 2014. 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 difficult because of the variety of potential discount
rates that can be used by the different participants as described in the TAG manual. Since the participant
benefit is based on the anticipated bill savings of the customer, Idaho Power believes the WACC is not
an appropriate discount rate to use. Because the customer bill savings is based on Idaho Power’s 2013 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 per kilowatt (kW). When multiplied by
the effective load carrying capacity (ELCC) of 93.4 percent, the annual avoided capacity cost is
$87.80/kW. The ELCC reduces the avoided capacity cost benefit.
Because demand response programs do not match the availability of generation resources,
these programs should not claim the full avoided capacity cost benefit of that supply-side resource. In 2011, Idaho Power determined the ELCC for demand response programs by creating load duration
curves using five years of actual total system load data and 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
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 4 Demand-Side Management 2013 Annual Report
to calculate the ELCC. Approximately 6.6 percent of the total hours were outside the programs’
parameters. Therefore, an ELCC of 93.4 percent is now applied to the avoided capacity cost of a
simple-cycle gas turbine in the cost-effectiveness calculation of demand response programs.
Net-to-Gross
Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE’s Understanding Cost-Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers as a ratio that does as follows:

Adjusts the impacts of the programs so that they only reflect those energy efficiency gains that
are the result of the energy efficiency program. Therefore, the NTG deducts energy savings that would have been achieved without the efficiency program (e.g., ‘free-riders’) and increases savings for any ‘spillover’ effect that occurs as an indirect result of the program. Since the NTG
attempts to measure what the customers would have done in the absence of the energy efficiency
program, it can be difficult to determine precisely.
For most programs and individual measures, the NTG ratios are sourced from the 2009 Nexant Demand-Side Management Potential Study. The NTG ratio adjustment is shown as part of
Supplement 1: Cost-Effectiveness for each program and measure. However, for some programs, such as
Energy Efficient Lighting, Irrigation Efficiency Rewards, and See ya later, refrigerator®, the unit
incremental savings are net realized energy savings from third-party sources that take into account an NTG ratio adjustment. While each project within the Custom Efficiency program is analyzed independently, and Idaho Power believes there is considerable spillover from this program, a NTG ratio
adjustment of 69 percent, the standard custom program NTG ratio from DEER2, which includes a
spillover adjustment, is used to calculate the cost-effectiveness of this program.
Results
Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis.
As part of Supplement 1: Cost-Effectiveness and where applicable, Idaho Power publishes the cost-effectiveness by measure, calculating the PCT and ratepayer impact measure (RIM) test at the
program level, listing the assumptions associated with cost-effectiveness, and citing sources and dates of
metrics used in the cost-effectiveness calculation.
The B/C ratio from the participant cost perspective is not calculated for the demand response programs,
Weatherization Assistance for Qualified Customers (WAQC), Weatherization Solutions for Eligible Customers, See ya later, refrigerator®, and Energy House Calls. These programs have few or no
customer costs. For energy efficiency programs, the cost-effectiveness models do not assume ongoing
participant costs.

2 Source: CPUC DEER NTFR Update Process for 2006–2007 Programs, found at
http://www.deeresources.com/files/deer2008exante/downloads/DEER%200607%20Measure%20Update%20Report.pdf

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 5
For most programs, the Demand-Side Management 2013 Annual Report contains program UC and TRC
B/C ratios using actual cost information over the life of the program through 2013. Supplement 1:
Cost-Effectiveness contains annual cost-effectiveness metrics for each program using actual information
from 2013, includes results of the PCT, and includes the application of an NTG factor where appropriate. Current customer energy rates are used in the calculation of the B/C ratios from a PCT and
RIM perspective. Rate increases are not forecast or escalated. Where applicable, the cost-effectiveness
results of demand response programs include historical expenses. A summary of the cost-effectiveness
by program can be found in Table 3.
In 2013, most of Idaho Power’s energy efficiency programs were cost effective, except for the Ductless Heat Pump Pilot, ENERGY STAR® Homes Northwest, and the weatherization programs for
income-qualified customers.
The Ductless Heat Pump Pilot has a UC of 2.51, TRC of 0.71, and PCT of 0.81. In fall 2013, the RTF
approved ductless heat pump annual savings estimates for customers not screened for supplemental fuel
use. RTF savings declined from the previously provisionally deemed savings of 3,500 annual kilowatt-hour (kWh) to a range between 292 kWh and 3,016 annual kWh. As a result of the lower kWh
savings, the program did not pass the TRC and PCT. The RTF will continue to evaluate ductless heat
pumps for the possible inclusion of NEBs for reduced wood purchases and decreased wood-burning
emissions. Idaho Power will continue to monitor the program in 2014.
The ENERGY STAR Homes Northwest program has a UC of 1.61, TRC of 0.95, and PCT of 1.46. In 2013, 7 of 267 homes were single-family homes and 260 were townhomes. Due to the lower kWh
savings for townhomes versus single-family homes, the program was shown to be not cost-effective
from a TRC perspective for 2013.
WAQC had a TRC of 0.74, and Weatherization Solutions for Eligible Customers had a TRC of 0.53 due
to the lower estimated savings per home that resulted from the impact evaluation conducted by D&R International. Idaho Power adopted the following IPUC staff’s recommendations from Case No.
GNR-E-12-01 for calculating the programs’ cost-effectiveness:
• Applied a 100-percent NTG.
• Claimed 100 percent of energy savings for each project.
• Included indirect administrative overhead costs. The overhead costs of 2.76 percent were
calculated from the $741,287 of indirect program expenses divided by the total DSM
expenses of $26,841,379 as shown in Appendix 3 of the Demand-Side Management 2013 Annual Report.
• Applied the 10-percent conservation preference adder.
• Amortized evaluation expenses over a three-year period.
• Claimed one dollar of NEBs for each dollar of utility and federal funds invested in health, safety, and repair measures.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 6 Demand-Side Management 2013 Annual Report
No cost-effectiveness analysis was performed on the A/C Cool Credit and Irrigation Peak Rewards
programs for 2013 due to the temporary suspension of the programs. In Case No. IPC-E-12-29,
the company filed a settlement stipulation with the IPUC on February 14, 2003. In the stipulation,
parties recognized the need for the company to incur program expenses in 2013 to maintain the programs’ infrastructure for the long-term, though it may not be cost effective by traditional standards.
The IPUC approved the settlement stipulation in Order No. 32776 on April 2, 2013.
The FlexPeak Management program was the only demand response program in operation in 2013.
Idaho Power amended its contract with EnerNOC to operate the FlexPeak Management program in 2013
at a reduced cost. Based on these contract amendments, the cost-effectiveness analysis for the program was updated using a 5-year program life versus the previously analyzed 10-year program life.
Idaho Power also calculates cost-effectiveness for each demand response program on a year-to-year
basis. For 2013, FlexPeak Management had a TRC 1.41. The 5-year program life TRC ratio for
FlexPeak Management program was 1.43.
Eighteen individual measures in various programs are shown to be not cost-effective from a TRC perspective. The measures will be discontinued, analyzed for additional NEBs, modified to increase
potential per unit savings, or monitored to examine their impact on the specific program’s overall
cost-effectiveness.
Table 1. 2013 non-cost-effective measures
Program Number of Measures Notes
Ductless Heat Pump Pilot 5 Measures will be monitored in 2014. RTF to analyze for additional NEBs
Easy Upgrades 1 Measure will be removed in 2014 due to minimal per-unit savings.
Energy Efficient Lighting 2 One measure will be removed from the program in 2014 due to negative per-unit savings. One measure will be reviewed in 2014.
ENERGY STAR Homes Northwest 1 Measure will be reviewed in 2014.
Heating & Cooling Efficiency Program 3 Measures will be reviewed in 2014.
Home Improvement 2 Measures will be reviewed in 2014.
Home Products Program 4 Measures will be reviewed in 2014.
Total 18

In addition to these 18 measures, 2 residential ENERGY STAR clothes washer and 2 residential
refrigerator measures fail the UC but pass the TRC. With the inclusion of NEBs, such as gas,
wastewater, and detergent savings, the clothes washers do pass the TRC test; however, the ‘any’ ENERGY STAR clothes washers option still fails the UC test. Idaho Power is now looking at adding
clothes washers to the program using a qualified product list for clothes washers meeting a higher
modified energy factor (MEF). Two refrigerator measures fail the UC test but pass the TRC test due to
the incentives being higher than the incremental costs. Idaho Power will continue to monitor
these measures.
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
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 7
not provide incentives for installed end-use measures. Other programs not analyzed at the measure level
include Custom Efficiency, the custom option of Irrigation Efficiency Rewards, and WAQC,
where projects include multiple interactive measures that are analyzed at the project level. Due to the
application of a per-home annual energy savings number for Weatherization Solutions for Eligible Customers determined by the 2012 impact evaluation, measure-level realized energy-saving data are
unavailable for 2013. The measure level cost-effectiveness analysis is not included in this report due to
the lack of realized data at the measure level.
The measure-level cost-effectiveness includes inputs of measure life, energy savings, incremental cost,
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.
Energy and expense data have been rounded to the nearest whole unit which may result in minor
rounding differences.
2013 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 2013 Annual Report. These expenses are broken out by funding source
major-expense type (incentives, labor/administration, materials, other expenses, and purchased services).
Table 2. 2013 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 ......................................................................... $ 537,163 $ 29,731 $ 96,964 $ 663,858
Labor/Administrative Expense ............................................ 81,728 4,300 0 86,028
Other Expense.................................................................... 43,925 2,442 0 46,367
Purchased Services ............................................................ 411,426 21,655 0 433,081
Incentives ........................................................................... 83 1,333 96,964 98,381
Ductless Heat Pump Pilot ........................................................ 230,761 6,814 0 237,575
Labor/Administrative Expense ............................................ 56,170 2,956 0 59,126
Other Expense.................................................................... 5,702 298 0 6,000
Purchased Services ............................................................ 10,639 560 0 11,199
Incentives ........................................................................... 158,250 3,000 0 161,250
Energy Efficient Lighting ......................................................... 1,331,113 25,812 0 1,356,926
Labor/Administrative Expense ............................................ 45,809 2,411 0 48,221
Other Expense.................................................................... 18,398 1,108 0 19,506
Purchased Services ............................................................ 383,288 8,240 0 391,528
Incentives ........................................................................... 883,618 14,053 0 897,671
Energy House Calls .................................................................. 164,173 35,822 0 199,995
Labor/Administrative Expense ............................................ 30,329 1,582 0 31,911
Materials and Equipment .................................................... 143 4 0 148
Other Expense.................................................................... 8,983 473 0 9,456
Purchased Services ............................................................ 124,718 33,762 0 158,480
ENERGY STAR® Homes Northwest ......................................... 344,217 4,664 4,000 352,882
Labor/Administrative Expense ............................................ 30,798 1,619 0 32,418
Other Expense.................................................................... 50,234 3,035 0 53,269
Purchased Services ............................................................ 185 10 0 195
Incentives ........................................................................... 263,000 0 4,000 267,000

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 8 Demand-Side Management 2013 Annual Report
Table 2. 2013 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Heating & Cooling Efficiency Program ................................... $ 317,973 $ 11,700 $ 0 $ 329,674
Labor/Administrative Expense ............................................ 60,834 3,201 0 64,035
Other Expense.................................................................... 86,409 4,706 0 91,114
Purchased Services ............................................................ 64,931 2,194 0 67,125
Incentives ........................................................................... 105,800 1,600 0 107,400
Home Energy Audit Program ................................................... 88,491 248 0 88,740
Labor/Administrative Expense ............................................ 26,506 248 0 26,754
Materials and Equipment .................................................... (235) 0 0 (235)
Other Expense.................................................................... 2,221 0 0 2,221
Purchased Services ............................................................ 60,000 0 0 60,000
Home Improvement Program ................................................... 299,032 0 465 299,497
Labor/Administrative Expense ............................................ 84,912 0 0 84,912
Other Expense.................................................................... 74,206 0 0 74,206
Purchased Services ............................................................ 225 0 0 225
Incentives ........................................................................... 139,690 0 465 140,155
Home Products Program.......................................................... 391,348 14,117 50 405,515
Labor/Administrative Expense ............................................ 48,188 2,532 0 50,720
Materials and Equipment .................................................... 20 1 0 21
Other Expense.................................................................... 18,054 950 50 19,055
Purchased Services ............................................................ 37,427 1,664 0 39,091
Incentives ........................................................................... 287,658 8,970 0 296,628
Oregon Residential Weatherization ......................................... 0 8,248 768 9,017
Labor/Administrative Expense ............................................ 0 6,002 768 6,770
Materials and Equipment .................................................... 0 349 0 349
Other Expense.................................................................... 0 465 0 465
Incentives ........................................................................... 0 1,433 0 1,433
Rebate Advantage .................................................................... 58,674 2,097 0 60,770
Labor/Administrative Expense ............................................ 9,236 484 0 9,720
Materials and Equipment .................................................... 16 1 0 17
Other Expense.................................................................... 11,622 612 0 12,234
Purchased Services ............................................................ 6,300 500 0 6,800
Incentives ........................................................................... 31,500 500 0 32,000
See ya later, refrigerator® ......................................................... 571,304 17,750 0 589,054
Labor/Administrative Expense ............................................ 44,651 2,334 0 46,985
Materials and Equipment .................................................... 58 3 0 61
Other Expense.................................................................... 49,258 2,321 0 51,580
Purchased Services ............................................................ 381,306 10,213 0 391,519
Incentives ........................................................................... 96,030 2,880 0 98,910
Weatherization Assistance for Qualified Customers ............. 0 0 1,391,677 1,391,677
Labor/Administrative Expense ............................................ 0 0 48,919 48,919
Materials and Equipment .................................................... 0 0 277 277
Other Expense.................................................................... 0 0 74,658 74,658
Purchased Services ............................................................ 0 0 1,267,824 1,267,824
Weatherization Solutions for Eligible Customers................... 1,239,132 0 28,659 1,267,791
Labor/Administrative Expense ............................................ 6,939 0 28,659 35,598
Other Expenses .................................................................. 85,742 0 0 85,742
Purchased Services ............................................................ 1,146,452 0 0 1,146,452
Residential Total ....................................................................... $ 5,573,384 $ 157,004 $ 1,522,584 $ 7,252,972

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 9
Table 2. 2013 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Commercial/Industrial
Building Efficiency ................................................................... $ 1,489,195 $ 17,839 $ 0 $ 1,507,035
Labor/Administrative Expense ............................................ 130,388 6,871 0 137,259
Other Expense.................................................................... 41,952 2,208 0 44,159
Purchased Services ............................................................ 166,444 8,760 0 175,204
Incentives ........................................................................... 1,150,412 0 0 1,150,412
Custom Efficiency .................................................................... 2,402,903 60,245 3,077 2,466,225
Labor/Administrative Expense ............................................ 429,340 22,598 3,190 455,128
Other Expense.................................................................... 246,048 9,268 0 255,316
Purchased Services ............................................................ 381,988 19,745 (113) 401,620
Incentives ........................................................................... 1,345,528 8,633 0 1,354,161
Easy Upgrades ......................................................................... 3,258,427 101,363 0 3,359,790
Labor/Administrative Expense ............................................ 237,898 12,521 0 250,419
Materials and Equipment .................................................... 250 13 0 263
Other Expense.................................................................... 145,303 7,637 0 152,941
Purchased Services ............................................................ 552,569 29,083 0 581,652
Incentives ........................................................................... 2,322,406 52,109 0 2,374,516
FlexPeak Management ............................................................. 108,842 137,184 2,497,589 2,743,615
Labor/Administrative Expense ............................................ 104,553 5,508 0 110,062
Other Expense.................................................................... 4,289 224 0 4,512
Purchased Services ............................................................ 0 0 0 0
Incentives ........................................................................... 0 131,452 2,497,589 2,629,041
Oregon Commercial Audit ....................................................... 0 5,090 0 5,090
Labor/Administrative Expense ............................................ 0 4,666 0 4,666
Other Expense.................................................................... 0 424 0 424
Commercial/Industrial Total ..................................................... $ 7,259,367 $ 321,722 $ 2,500,666 $ 10,081,756
Irrigation
Irrigation Efficiency .................................................................. 2,277,059 134,789 29,539 2,441,386
Labor/Administrative Expense ............................................ 316,392 16,641 29,539 362,572
Materials and Equipment .................................................... 222 12 0 233
Other Expense.................................................................... 85,956 4,600 0 90,556
Purchased Services ............................................................ 11,074 311 0 11,385
Incentives ........................................................................... 1,863,415 113,225 0 1,976,640
Irrigation Peak Rewards ........................................................... 407,496 30,117 1,634,494 2,072,107
Labor/Administrative Expense ............................................ 29,631 1,558 25,892 57,081
Other Expense.................................................................... 3,637 191 0 3,829
Purchased Services ............................................................ 374,228 19,696 0 393,924
Incentives ........................................................................... 0 8,670 1,608,602 1,617,272
Irrigation Total $ 2,684,555 $ 164,905 $ 1,664,033 $ 4,513,493
Energy Efficiency/Demand Response Total $ 15,517,306 $ 643,631 $ 5,687,283 $ 21,848,220
Market Transformation
NEEA ......................................................................................... 3,147,405 165,653 0 3,313,058
Purchased Services ............................................................ 3,147,405 165,653 0 3,313,058
Market Transformation Total ................................................... $ 3,147,405 $ 165,653 $ 0 $ 3,313,058

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 10 Demand-Side Management 2013 Annual Report
Table 2. 2013 DSM detailed expenses by program (continued)
Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program
Other Programs and Activities
Residential
Residential Education Initiative ............................................... $ 395,668 $ 20,498 $ 0 $ 416,166
Labor/Administrative Expense ............................................ 141,873 7,314 0 149,187
Materials and Equipment .................................................... 8,420 443 0 8,863
Other Expense.................................................................... 245,040 12,724 0 257,764
Purchased Services ............................................................ 334 18 0 352
Residential Economizer ........................................................... 74,901 0 0 74,901
Labor/Administrative Expense ............................................ 5,442 0 0 5,442
Other Expense.................................................................... 3 0 0 3
Purchased Services ............................................................ 69,456 0 0 69,456
Residential Total ....................................................................... $ 470,568 $ 20,498 $ 0 $ 491,067
Commercial/Industrial
Commercial Education Initiative .............................................. 63,451 3,339 0 66,790
Labor/Administrative Expense ............................................ 4,707 247 0 4,954
Other Expense.................................................................... 30,876 1,625 0 32,501
Purchased Services ............................................................ 27,868 1,467 0 29,335
Commercial/Industrial Total ..................................................... $ 63,451 $ 3,339 $ 0 $ 66,790
Other
Energy Efficiency Direct Program Overhead .......................... 361,910 19,047 0 380,957
Labor/Administrative Expense ............................................ 214,944 11,312 0 226,256
Materials and Equipment .................................................... 168 9 0 176
Other Expense.................................................................... 146,798 7,726 0 154,525
Other Total ................................................................................ $ 361,910 $ 19,047 $ 0 $ 380,957
Other Programs and Activities Total $ 895,929 $ 42,884 $ 0 $ 938,814
Indirect Program Expense
Residential Overhead ............................................................... 124,825 7,056 49 131,931
Labor/Administrative Expense ............................................ 91,360 4,807 0 96,167
Materials and Equipment .................................................... 193 7 49 249
Other Expense.................................................................... 16,863 872 0 17,736
Purchased Services ............................................................ 16,409 1,369 0 17,778
Commercial/Industrial Overhead ............................................. 136,811 7,708 0 144,518
Labor/Administrative Expense ............................................ 99,831 5,257 0 105,088
Materials and Equipment .................................................... 36 0 0 36
Other Expense.................................................................... 18,394 968 0 19,362
Purchased Services ............................................................ 18,550 1,482 0 20,032
Energy Efficiency Accounting and Analysis........................... 802,258 42,316 137,854 982,428
Labor/Administrative Expense ............................................ 430,935 22,686 133,328 586,949
Other Expense.................................................................... 57,210 3,011 4,526 64,747
Purchased Services ............................................................ 314,113 16,619 0 330,732
Energy Efficiency Advisory Group .......................................... 5,390 285 0 5,674
Labor/Administrative Expense ............................................ 4,726 250 0 4,976
Other Expense.................................................................... 664 35 0 698
Special Accounting Entries ..................................................... 13,838,199 6,007 (14,367,471) (523,265)
Indirect Program Expenses Total ............................................ $ 14,907,483 $ 63,371 $ (14,229,567) $ 741,287
Totals $ 34,468,123 $ 915,540 $ (8,542,284) $ 26,841,379

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 11
Table 3. Cost-effectiveness summary by program
2013 Benefit/Cost Tests
Program
Utility Cost
(UC)
Total Resource
Cost (TRC)
Ratepayer Impact
Measure (RIM)
Participant
Cost (PCT)
A/C Cool Credit .......................................................... N/A N/A N/A N/A
FlexPeak Management ............................................... 1.43 1.43 1.43 N/A
Irrigation Peak Rewards ............................................. N/A N/A N/A N/A
Ductless Heat Pump Pilot ........................................... 2.51 0.71 0.85 0.81
Energy Efficient Lighting ............................................. 4.79 2.61 0.89 2.96
Energy House Calls .................................................... 3.95 3.95 0.83 N/A
ENERGY STAR® Homes Northwest ........................... 1.61 0.95 0.71 1.46
Heating & Cooling Efficiency Program ........................ 3.87 1.93 0.98 2.54
Home Improvement Program ...................................... 3.58 1.18 0.88 1.43
Home Products Program ............................................ 1.69 2.24 0.69 3.42
Rebate Advantage ...................................................... 5.39 3.80 0.91 6.38
See ya later, refrigerator® ........................................... 1.23 1.23 0.58 N/A
Weatherization Assistance for Qualified Customers .... 0.95 0.74 0.56 N/A
Weatherization Solutions for Eligible Customers ......... 0.46 0.53 0.35 N/A
Building Efficiency ...................................................... 5.48 3.26 1.31 2.94
Custom Efficiency ....................................................... 5.61 2.56 1.81 1.58
Easy Upgrades ........................................................... 4.71 2.61 1.26 2.42
Irrigation Efficiency ..................................................... 6.35 1.72 1.63 1.17

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 12 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 13
COST-EFFECTIVENESS TABLES BY PROGRAM
FlexPeak Management
Segment: Commercial/Industrial
5-Year Program Cost-Effectiveness Summary
Program Inception:2009

Cost Inputs (net-present value [NPV]) Ref Summary of Cost-Effectiveness Results
Total Program Administration .............................................................................. $ 408,039 Test Benefit Cost Ratio
Total Program Incentives ..................................................................................... 9,834,490 Utility Cost Test ............................. $ 14,652,073 $ 10,254,941 1.43
Total Utility Cost ................................................................................................ $ 10,242,529 P Total Resource Cost Test .............. 14,652,073 10,254,941 1.43
Ratepayer Impact Measure Test ... 14,652,073 10,242,529 1.43
Total Shifted Energy Utility Cost .......................................................................... 12,412 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) ......................................................... 4,487,257 $ 296,833 Total Resource Cost Test ................................ = S + NUI + NEB = P + M + SE
2013 Reduction Capacity (MW) ................................................ 40 14,355,239 Ratepayer Impact Measure Test ..................... = S = P + B
Total Electric Savings ................................................................ $ 14,652,073 S Participant Cost Test ....................................... N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ — B Discount Rate
Nominal (Weighted Average Cost of Capital [WACC]) ............................. 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) - 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate .......................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Effective Load Carrying Capacity (ELCC) ................................................... 93.40%
Summer Peak Line Loss (for Demand Response ....................................... 13.00%
Line Losses ................................................................................................ 10.90%
Notes: Based on a contract amendment with EnerNOC signed in 2013, cost-effectiveness analysis for the program updated using a 5-year program life versus the previously analyzed 10-year
program life.
As part of the public workshops for Case No. IPC-E-13-14 and approved in Order No. 32923, the new methodology for valuing demand response will be applied to demand response cost-effectiveness models in 2014.
2013 Reduction capacity based on contracted target of 35 MW (40 megawatt [MW] with Summer Peak Line Loss of 13%).
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 14 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 15
Ductless Heat Pump Pilot
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 76,325 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 161,250 I Utility Cost Test ............................. $ 595,951 $ 237,575 2.51
Total Utility Cost ................................................................................................ $ 237,575 P Total Resource Cost Test .............. 595,951 841,467 0.71
Ratepayer Impact Measure Test ... 595,951 702,627 0.85
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 916,115 M Participant Cost Test ..................... 742,565 916,115 0.81

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 589,142 $ Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 6,576,617 744,939 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 744,939 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 581,315 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%
Notes: This program is not cost-effective due to lower per-unit deemed savings from the Regional Technical Forum (RTF). Program will be monitored in 2014 for the potential inclusion of non-energy benefits.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 16 Demand-Side Management 2013 Annual Report
Year:2013 Program: Ductless Heat Pump Pilot Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Ductless Heat Pump No supplemental fuel screen. Heating zone 2, cooling zone 1.
Zonal Electric Unit ENRes_SF_HeatPump 15 80% 2,585.00 $3,061.75 $– $4,261.00 $750.00 $0.130 2.26 0.63 1,2
Ductless Heat Pump No supplemental fuel screen. Heating zone 3, cooling zone 1.
Zonal Electric Unit ENRes_SF_HeatPump 15 80% 292.00 $345.85 $– $4,261.00 $750.00 $0.130 0.35 0.08 1,2
Ductless Heat Pump No supplemental fuel screen. Heating zone 2, cooling zone 2.
Zonal Electric Unit ENRes_SF_HeatPump 15 80% 2,746.00 $3,252.45 $– $4,261.00 $750.00 $0.130 2.35 0.66 1,2
Ductless
Heat Pump
No supplemental fuel
screen. Heating zone 1, cooling zone 3.
Zonal
Electric
Unit ENRes_SF_HeatPump 15 80% 3,131.00 $3,708.45 $– $4,261.00 $750.00 $0.130 2.56 0.75 1,2
Ductless Heat Pump No supplemental fuel screen. Heating zone 2, cooling zone 3.
Zonal Electric Unit ENRes_SF_HeatPump 15 80% 3,016.00 $3,572.24 $– $4,261.00 $750.00 $0.130 2.50 0.72 1,2
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives. Based on 2013 average customer costs.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Regional Technical Forum (RTF). ResHeatingCoolingDuctlessHeatPumpsSF_v1_5.xls. 2014.
2 Measure combination not cost-effective. Will be monitored in 2014.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 17
Energy Efficient Lighting
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 459,255 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 897,671 I Utility Cost Test ............................. $ 6,499,196 $ 1,356,926 4.79
Total Utility Cost ................................................................................................ $ 1,356,926 P Total Resource Cost Test .............. 12,745,173 4,889,501 2.61
Ratepayer Impact Measure Test ... 6,499,196 7,308,895 0.89
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 4,430,246 M Participant Cost Test ..................... 13,095,617 4,430,246 2.96

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 9,995,753 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 72,951,593 $ 6,499,196 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 6,499,196 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 5,951,969 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ 6,245,977 NEB Net-to-Gross (NTG) .................................................................................... 100.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%
Notes: No NTG. Deemed savings from the RTF already accounts for net realized energy savings.
NEBs include PV of periodic bulb (capital) replacement costs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 18 Demand-Side Management 2013 Annual Report
Year:2013 Program: Energy Efficient Lighting Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)e
Gross Incremental Participant Costf Incentive/ Unit Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Dimmable Reflector CFL
Retail. 1,015–1,439 lumens. Dimmable Reflector—All
Baseline bulb lamp ENRes_SF_Lighting 7 100% 18.00 $9.65 $9.03 $8.62 $2.00 $0.046 3.41 1.98 1
General Purpose CFL
Retail. 1,015–1,439 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 8 100% 13.00 $7.93 $3.08 $3.62 $2.00 $0.046 3.05 2.61 1
Reflector CFL Retail. 1,015–1,439 lumens. Reflector—All Baseline bulb lamp ENRes_SF_Lighting 7 100% 18.00 $9.65 $9.03 $8.62 $2.00 $0.046 3.41 1.98 1
3-Way CFL Retail. 1,440–2,019 lumens. 3-Way—All Baseline bulb lamp ENRes_SF_Lighting 11 100% 29.00 $23.90 $10.84 $11.41 $2.00 $0.046 7.17 2.73 1
General Purpose CFL
Retail. 1,440–2,019 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 9 100% 8.00 $5.46 $2.54 $3.62 $2.00 $0.046 2.31 2.00 1
3-Way CFL Retail. 2,020–2,600 lumens. 3-Way—All Baseline bulb lamp ENRes_SF_Lighting 11 100% 22.00 $18.13 $5.29 $11.16 $2.00 $0.046 6.02 1.92 1
General Purpose CFL
Retail. 2,020–2,600 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 9 100% 12.00 $8.19 $6.74 $12.09 $2.00 $0.046 3.21 1.18 1
CC Candelabra decorative CFL
Retail. 250–369 lumens. CC Candelabra: decorative—All
Baseline bulb lamp ENRes_SF_Lighting 20 100% 1.00 $1.38 $3.65 $5.22 $2.00 $0.046 0.67 0.95 1, 2
Globe CFL Retail. 250–369 lumens. Globe-All Baseline bulb lamp ENRes_SF_Lighting 7 100% (1.00) $(0.54) $3.39 $4.30 $2.00 $0.046 -0.27 0.67 1, 3
Reflector CFL Retail. 250–369 lumens. Reflector—All Baseline bulb lamp ENRes_SF_Lighting 9 100% 4.00 $2.73 $17.60 $5.96 $2.00 $0.046 1.25 3.31 1
CC Candelabra decorative CFL
Retail. 370–664 lumens. CC Candelabra: decorative—All
Baseline bulb lamp ENRes_SF_Lighting 20 100% 10.00 $13.78 $4.74 $4.80 $2.00 $0.046 5.60 3.52 1
General Purpose CFL
Retail. 370 to 664 lumens. General Purpose-All
Baseline bulb lamp ENRes_SF_Lighting 9 100% 7.00 $4.78 $3.68 $3.13 $2.00 $0.046 2.06 2.45 1
Globe CFL Retail. 370–664 lumens. Globe—All Baseline bulb lamp ENRes_SF_Lighting 7 100% 6.00 $3.22 $6.33 $5.88 $2.00 $0.046 1.41 1.55 1
Reflector CFL Retail. 370–664 lumens. Reflector—All Baseline bulb lamp ENRes_SF_Lighting 9 100% 9.00 $6.15 $18.71 $6.70 $2.00 $0.046 2.55 3.50 1
CC
Candelabra decorative CFL
Retail. 665–1,014
lumens. CC Candelabra: decorative—All
Baseline bulb lamp ENRes_SF_Lighting 20 100% 16.00 $22.05 $4.96 $5.83 $2.00 $0.046 8.06 4.11 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 19
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)e
Gross Incremental Participant Costf Incentive/ Unit Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Dimmable Reflector CFL
Retail. 665–1,014 lumens. Dimmable Reflector—All
Baseline bulb lamp ENRes_SF_Lighting 9 100% 15.00 $10.24 $18.64 $6.78 $2.00 $0.046 3.81 3.87 1
General Purpose CFL
Retail. 665–1,014 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 9 100% 8.00 $5.46 $2.82 $2.96 $2.00 $0.046 2.31 2.49 1
Globe CFL Retail. 665–1,014 lumens. Globe—All Baseline bulb lamp ENRes_SF_Lighting 7 100% 8.00 $4.29 $11.24 $5.83 $2.00 $0.046 1.81 2.50 1
Reflector CFL Retail. 665–1,014 lumens. Reflector—All Baseline bulb lamp ENRes_SF_Lighting 9 100% 15.00 $10.24 $18.64 $6.78 $2.00 $0.046 3.81 3.87 1
General Purpose CFL
Give-Away. 1,440–2,019 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 8 100% 8.00 $4.88 $2.49 $-– $-– $0.046 13.26 20.03 1
General Purpose CFL
Give-Away. 1,015–1,439 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 7 100% 13.00 $6.97 $5.74 $-– $-– $0.046 11.65 21.25 1
General Purpose CFL
Give-Away. 665–1,014 lumens. General Purpose—All
Baseline bulb lamp ENRes_SF_Lighting 8 100% 8.00 $4.88 $2.31 $-– $-– $0.046 13.26 19.54 1
a Average measure life.
b No Net-to-Gross (NTG) percentage. Deemed savings from RTF includes realization rate.
c Estimated kWh savings measured at the customers meter, excluding line losses. d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Present value of periodic replacement costs.
f Incremental participant cost prior to customer incentives.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResCFLLighting_v3_0.xlsm. Retail. Any Interior. 2013.
2 Measure not cost-effective. Will be reviewed in 2014.
3 Measure has negative savings. Will be removed from the program in 2014.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 20 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 21
Energy House Calls
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 199,995 Test Benefit Cost Ratio
Program Incentives .............................................................................................. — I Utility Cost Test ............................. $ 790,769 $ 199,995 3.95
Total Utility Cost ................................................................................................ $ 199,995 P Total Resource Cost Test .............. 790,769 199,995 3.95
Ratepayer Impact Measure Test ... 790,769 953,532 0.83
Measure Equipment and Installation (Incremental Participant Cost) .................... $ — M Participant Cost Test ..................... N/A N/A N/A

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 837,261 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 10,305,000 $ 988,461 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 988,461 S Participant Cost Test .......................... N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 941,921 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%
Notes: No participant costs.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 22 Demand-Side Management 2013 Annual Report
Year:2013 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: PTCS Duct Sealing: Heating Zone 1 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 1,496.00 $1,627.40 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2)
Manufactured Home Duct Tightness: Heating Zone 1 (Electric FAF Heating System w/o CAC)
Pre-
existing duct leakage
Home ENRes_MH_Heater 18 80% 1,433.00 $1,558.87 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 1 (Electric Heat Pump Heating System)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 887.00 $964.91 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 2 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,361.00 $2,568.38 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 2 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,290.00 $2,491.15 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 2
(Electric Heat Pump Heating System)
Pre-existing duct
leakage
Home ENRes_MH_Heater 18 80% 1,664.00 $1,810.16 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 3 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 3,074.00 $3,344.01 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 3 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 3,023.00 $3,288.53 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Single Wide (<= 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 3 (Electric Heat Pump Heating System)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,324.00 $2,528.13 $— $— $— $0.239 3.64 3.64 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 23
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 1 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 1,881.00 $2,046.22 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness : Heating Zone 1 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 1,799.00 $1,957.02 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 1 (Electric Heat Pump Heating System)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 1,093.00 $1,189.01 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2)
Manufactured Home Duct Tightness: Heating Zone 2 (Electric FAF Heating System w/CAC)
Pre-
existing duct leakage
Home ENRes_MH_Heater 18 80% 2,898.00 $3,152.55 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 2 (Electric FAF Heating System w/o CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,791.00 $3,036.15 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 2 (Electric Heat Pump Heating System)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,022.00 $2,199.61 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 3 (Electric FAF Heating System w/CAC)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 3,710.00 $4,035.87 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2)
Manufactured Home Duct Tightness: Heating Zone 3 (Electric FAF Heating System w/o CAC)
Pre-
existing duct leakage
Home ENRes_MH_Heater 18 80% 3,645.00 $3,965.17 $— $— $— $0.239 3.64 3.64 1
PTCS Duct Sealing Other (> 1,000 ft2) Manufactured Home Duct Tightness: Heating Zone 3 (Electric Heat Pump Heating System)
Pre-existing duct leakage
Home ENRes_MH_Heater 18 80% 2,813.00 $3,060.09 $— $— $— $0.239 3.64 3.64 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 24 Demand-Side Management 2013 Annual Report
e No participant cost.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResHeatingCoolingDuctSealingMH_v2_4.xlsm. 2012.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 25
ENERY STAR® Homes Northwest
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 85,882 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 267,000 I Utility Cost Test ............................. $ 569,607 $ 352,882 1.61
Total Utility Cost ................................................................................................ $ 352,882 P Total Resource Cost Test .............. 569,607 598,258 0.95
Ratepayer Impact Measure Test ... 569,607 797,990 0.71
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 607,800 M Participant Cost Test ..................... 885,205 607,800 1.46

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 365,370 $ Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 5,839,337 $ 791,120 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 791,120 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 618,205 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 72.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%
Notes: 2009 International Energy Conservation Code (IECC) adopted in Idaho in 2011.

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 26 Demand-Side Management 2013 Annual Report
Year:2013 Program: ENERGY STAR Homes Northwest Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
ENERGY STAR home
Home in Idaho or Montana with Heat Pump: Heating Zone 1 Cooling Zone 3
Single-family home built to International Energy Conservation Code (IECC) 2009 Code. Adopted 2011.
Home IPC_Residential 37 72% 3,778.00 $8,702.87 $— $3,915.69 $1,000.00 $0.246 3.25 1.56 1
ENERGY
STAR home
Home in Idaho or
Montana built to the DHP TCO: Heating Zone 1 Cooling Zone 3
Single family home
built to IECC 2009 Code. Adopted 2011.
Home IPC_Residential 37 72% 4,844.00 $11,158.48 $— $5,624.69 $1,000.00 $0.246 3.67 1.46 2
ENERGY STAR home
Multifamily—Heat Pump: Heating Zone 1 Cooling Zone 3
Multi-family home built to IECC 2009 Code. Adopted 2011.
Home IPC_Residential 36 72% 1,294.00 $2,943.67 $— $2,294.95 $1,000.00 $0.246 1.61 0.94 3, 4
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResNewSFEStarWAIDMT_v2_2.xls. 2012.
2 RTF. EStarNWSFHomes_DHPtco_WAIDMT_v1_0.xls. 2011.
3 RTF. ResMFEstarHomes2012_v1_1.xlsm. 2012.
4 Measure combination not cost-effective. Will monitor in 2014.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 27
Heating & Cooling Efficiency Program
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 222,274 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 107,400 I Utility Cost Test ............................. $ 1,275,518 $ 329,674 3.87
Total Utility Cost ................................................................................................ $ 329,674 P Total Resource Cost Test .............. 1,275,518 659,203 1.93
Ratepayer Impact Measure Test ... 1,275,518 1,300,322 0.98
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 519,312 M Participant Cost Test ..................... 1,320,710 519,312 2.54

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 1,003,730 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 13,039,162 $ 1,594,397 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 1,594,397 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 1,213,310 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 28 Demand-Side Management 2013 Annual Report
Year:2013 Program: Heating & Cooling Efficiency Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Air Conditioning (A/C) & Heat Pump Units
Evaporative cooler single family Central A/C Unit ENRes_SF_CAC 12 80% 416.00 $605.56 $— $— $150.00 $0.221 2.00 2.00 1
A/C & Heat Pump Units Evaporative cooler manufactured home Central A/C Unit ENRes_MH_CAC 12 80% 309.00 $483.50 $— $— $150.00 $0.221 1.77 1.77 1
A/C & Heat Pump Units Evaporative cooler multi-family Central A/C Unit ENRes_MH_CAC 12 80% 296.00 $425.92 $— $— $150.00 $0.221 1.58 1.58 1
A/C & Heat Pump Units Open-loop water
source heat pump for existing and new construction: 14.00 EER 3.5 COP
Electric
resistance/Oil Propane
Unit ENRes_SF_HeatPump 20 80% 8,927.00 $13,276.62 $— $11,425.00 $1,000.00 $0.221 3.57 0.94 2, 3
A/C & Heat Pump Units Open-loop water source heat pump: 14.00 EER 3.5 COP
Air-source heat pump Unit ENRes_SF_HeatPump 20 80% 2,648.00 $3,938.22 $— $4,435.00 $500.00 $0.221 2.90 0.74 2, 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 with central A/C
Unit ENRes_SF_HeatPump 20 80% 5,306.00 $7,891.31 $— $4,165.00 $800.00 $0.221 3.20 1.35 3, 6
A/C & Heat Pump Units Single-family home HVAC Conversions: Convert to Heat Pump 8.50 HSPF Heating Zone 2
Forced air furnace with central A/C
Unit ENRes_SF_HeatPump 20 80% 6,961.00 $10,352.70 $— $4,165.00 $800.00 $0.221 3.54 1.65 3, 6
A/C & Heat Pump Units Single-family home HVAC Conversions: Convert to Heat
Pump 8.50 HSPF Heating Zone 3
Forced air furnace with central
A/C
Unit ENRes_SF_HeatPump 20 80% 7,876.00 $11,713.52 $— $4,165.00 $800.00 $0.221 3.69 1.79 3, 6
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 ENRes_SF_HeatPump 20 80% 4,380.00 $6,514.12 $— $6,398.00 $800.00 $0.221 2.95 0.83 3, 4, 6
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 ENRes_SF_HeatPump 20 80% 6,719.00 $9,992.78 $— $6,398.00 $800.00 $0.221 3.50 1.18 3, 6
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 29
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
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 ENRes_SF_HeatPump 20 80% 6,451.00 $9,594.20 $— $6,398.00 $800.00 $0.221 3.45 1.14 3, 6
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 ENRes_SF_HeatPump 20 80% 6,035.00 $8,975.51 $— $6,398.00 $800.00 $0.221 3.37 1.09 3, 6
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 ENRes_SF_HeatPump 20 80% 7,634.00 $11,353.61 $— $6,398.00 $800.00 $0.221 3.65 1.30 3, 6
A/C & Heat Pump Units Existing single-family home Heat Pump: upgraded to 8.50 HSPF All Climates
Heat pump Unit ENRes_SF_HeatPump 20 80% 2,597.00 $3,862.37 $— $1,850.00 $250.00 $0.221 3.75 1.47 1, 5
A/C & Heat Pump Units Existing single-family home Heat Pump: upgraded to 9.0
HSPF/14 SEER Heating Zone 1
Heat pump Unit ENRes_SF_HeatPump 15 80% 128.00 $151.61 $— $58.67 $— $0.221 4.29 1.61 7, 8
A/C & Heat Pump Units Existing single-family home Heat Pump: upgraded to 9.0 HSPF/14 SEER Heating Zone 2
Heat pump Unit ENRes_SF_HeatPump 15 80% 116.00 $137.39 $— $58.67 $— $0.221 4.29 1.51 7, 8
A/C & Heat Pump Units Existing single-family home Heat Pump: upgraded to 9.0 HSPF/14 SEER Heating Zone 3
Heat pump Unit ENRes_SF_HeatPump 15 80% 115.00 $136.21 $— $58.67 $— $0.221 4.29 1.51 7, 8
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009. c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives. Based on 2012–2013 median customer costs.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Idaho Power Energy Efficiency Potential Study by EnerNOC Utility Solutions Consulting. IPC Residential LoadMAP.
2 Savings from Ecotope, Inc., heat pump sizing specifications and heat pump measure savings estimates. December 2009.
3 Costs based on average 2013 local contractor costs.
4 Measure not cost-effective due to high incremental costs. Will monitor in 2014.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 30 Demand-Side Management 2013 Annual Report
5 Costs based on incremental difference between technology and RTF survey data.
6 Savings from RTF. Res_SFHPConversion_V2_6.xlsm.2012.
7 RTF. ResHeatingCoolingHeatPumpUpgradeSF_v2_8.xlsm. 2012.
8 Customers receive incentive for going to an efficiency of at least an 8.5 HSPF heat pump. Incremental savings claimed for projects with an efficiency greater than a 9.0 HSPF. No additional incentive paid.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 31
Home Improvement Program
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 159,343 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 140,155 I Utility Cost Test ............................. $ 1,073,443 $ 299,497 3.58
Total Utility Cost ................................................................................................ $ 299,497 P Total Resource Cost Test .............. 1,073,443 908,578 1.18
Ratepayer Impact Measure Test ... 1,073,443 1,215,734 0.88
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 901,506 M Participant Cost Test ..................... 1,285,452 901,506 1.43

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 616,044 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 10,268,456 $ 1,341,804 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 1,341,804 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 1,145,298 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 32 Demand-Side Management 2013 Annual Report
Year:2013 Program: Home Improvement Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R0 to R38. Average electric heating system w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 2.06 $4.06 $- $0.55 $0.15 $0.259 4.75 3.24 1
Single Family: Attic Insulation
R0 to R38. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 2.87 $5.66 $- $0.55 $0.15 $0.259 5.07 3.73 1
Single Family: Attic Insulation
R0 to R38. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 2.87 $5.66 $- $0.55 $0.15 $0.259 5.07 3.73 1
Single Family: Attic Insulation
R0 to R38. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 2.87 $5.66 $- $0.55 $0.15 $0.259 5.07 3.73 1
Single Family:
Attic Insulation
R0 to R38. Average electric heating system
w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 3.49 $6.87 $- $0.55 $0.15 $0.259 5.22 4.01 1
Single Family: Attic Insulation
R0 to R38. Average Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.28 $5.32 $- $0.55 $0.15 $0.259 5.76 4.02 1
Single Family: Attic Insulation
R0 to R38. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.97 $6.94 $- $0.55 $0.15 $0.259 6.04 4.48 1
Single
Family: Attic Insulation
R0 to R38. Average
Heating System w/ CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation
R0 to R38
ft2 ENRes_SF_HeatPump 45 80% 3.01 $7.05 $- $0.55 $0.15 $0.259 6.06 4.51 1
Single Family: Attic Insulation
R0 to R38. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 3.09 $7.22 $- $0.55 $0.15 $0.259 6.08 4.55 1
Single Family: Attic Insulation
R0 to R38. Average Heating System w/ CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 3.58 $8.38 $- $0.55 $0.15 $0.259 6.22 4.79 1
Single Family: Attic Insulation
R0 to R38. Electric FAF Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.65 $6.20 $- $0.55 $0.15 $0.259 5.93 4.29 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 33
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R0 to R38. Electric FAF Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 3.29 $6.49 $- $0.55 $0.15 $0.259 5.18 3.93 1
Single Family: Attic Insulation
R0 to R38. Heat pump. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 1.44 $3.37 $- $0.55 $0.15 $0.259 5.15 3.20 1
Single Family: Attic Insulation
R0 to R38. Heat pump. Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.18 $5.10 $- $0.55 $0.15 $0.259 5.71 3.94 1
Single Family: Attic Insulation
R0 to R38. Heat pump. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.23 $5.20 $- $0.55 $0.15 $0.259 5.73 3.98 1
Single Family: Attic Insulation
R0 to R38. Heat pump. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.30 $5.38 $- $0.55 $0.15 $0.259 5.77 4.04 1
Single Family: Attic Insulation
R0 to R38. Heat pump. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R38 ft2 ENRes_SF_HeatPump 45 80% 2.91 $6.79 $- $0.55 $0.15 $0.259 6.02 4.45 1
Single
Family: Attic Insulation
R0 to R38. Zonal
Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R38 ft2 ENRes_SF_Heater 45 80% 2.17 $4.29 $- $0.55 $0.15 $0.259 4.81 3.32 1
Single Family: Attic Insulation
R0 to R49. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 3.28 $7.68 $- $0.55 $0.15 $0.259 6.14 4.65 1
Single Family: Attic Insulation
R0 to R49. Average electric heating system w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 2.19 $4.32 $- $0.55 $0.15 $0.259 4.82 3.33 1
Single
Family: Attic Insulation
R0 to R49. Average
electric heating system w/o CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.05 $6.02 $- $0.55 $0.15 $0.259 5.12 3.82 1
Single Family: Attic Insulation
R0 to R49. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.05 $6.02 $- $0.55 $0.15 $0.259 5.12 3.82 1
Single Family: Attic Insulation
R0 to R49. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.05 $6.02 $- $0.55 $0.15 $0.259 5.12 3.82 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 34 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R0 to R49. Average electric heating system w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.71 $7.31 $- $0.55 $0.15 $0.259 5.27 4.09 1
Single Family: Attic Insulation
R0 to R49. Average Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 2.42 $5.66 $- $0.55 $0.15 $0.259 5.83 4.13 1
Single Family: Attic Insulation
R0 to R49. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 3.15 $7.37 $- $0.55 $0.15 $0.259 6.10 4.58 1
Single Family: Attic Insulation
R0 to R49. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 3.20 $7.49 $- $0.55 $0.15 $0.259 6.12 4.61 1
Single Family: Attic Insulation
R0 to R49. Average Heating System w/ CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 3.81 $8.91 $- $0.55 $0.15 $0.259 6.27 4.89 1
Single Family: Attic Insulation
R0 to R49. Electric FAF Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 2.82 $6.59 $- $0.55 $0.15 $0.259 5.99 4.39 1
Single
Family: Attic Insulation
R0 to R49. Electric FAF
Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 2.59 $5.10 $- $0.55 $0.15 $0.259 4.98 3.58 1
Single Family: Attic Insulation
R0 to R49. Electric FAF Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.50 $6.91 $- $0.55 $0.15 $0.259 5.23 4.01 1
Single Family: Attic Insulation
R0 to R49. Heat pump. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 1.53 $3.58 $- $0.55 $0.15 $0.259 5.24 3.31 1
Single
Family: Attic Insulation
R0 to R49. Heat pump.
Heating Zone 2 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 2.31 $5.40 $- $0.55 $0.15 $0.259 5.77 4.04 1
Single Family: Attic Insulation
R0 to R49. Heat pump. Heating Zone 2 Cooling Zone 2
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 2.36 $5.52 $- $0.55 $0.15 $0.259 5.80 4.08 1
Single Family: Attic Insulation
R0 to R49. Heat pump. Heating Zone 2 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 2.44 $5.70 $- $0.55 $0.15 $0.259 5.84 4.14 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 35
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R0 to R49. Heat pump. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_HeatPump 45 80% 3.08 $7.20 $— $0.55 $0.15 $0.259 6.08 4.54 1
Single Family: Attic Insulation
R0 to R49. Zonal Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 2.31 $4.56 $— $0.55 $0.15 $0.259 4.87 3.41 1
Single Family: Attic Insulation
R0 to R49. Zonal Heating System w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R0 to R49 ft2 ENRes_SF_Heater 45 80% 3.69 $7.27 $— $0.55 $0.15 $0.259 5.26 4.08 1
Single Family: Attic Insulation
R19 to R38. Average electric heating system w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.56 $1.10 $— $0.55 $0.15 $0.259 2.98 1.43 1
Single Family: Attic Insulation
R19 to R38. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.78 $1.53 $— $0.55 $0.15 $0.259 3.49 1.82 1
Single Family: Attic Insulation
R19 to R38. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.78 $1.53 $— $0.55 $0.15 $0.259 3.49 1.82 1
Single
Family: Attic Insulation
R19 to R38. Average
electric heating system w/o CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.78 $1.53 $— $0.55 $0.15 $0.259 3.49 1.82 1
Single Family: Attic Insulation
R19 to R38. Average electric heating system w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.94 $1.86 $— $0.55 $0.15 $0.259 3.77 2.08 1
Single Family: Attic Insulation
R19 to R38. Average Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.61 $1.44 $— $0.55 $0.15 $0.259 3.72 1.83 1
Single
Family: Attic Insulation
R19 to R38. Average
Heating System w/ CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.80 $1.87 $— $0.55 $0.15 $0.259 4.19 2.21 1
Single Family: Attic Insulation
R19 to R38. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.81 $1.90 $— $0.55 $0.15 $0.259 4.22 2.23 1
Single Family: Attic Insulation
R19 to R38. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.83 $1.95 $— $0.55 $0.15 $0.259 4.26 2.27 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 36 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R19 to R38. Average Heating System w/ CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.97 $2.26 $— $0.55 $0.15 $0.259 4.52 2.51 1
Single Family: Attic Insulation
R19 to R38. Electric FAF Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.72 $1.68 $— $0.55 $0.15 $0.259 4.00 2.05 1
Single Family: Attic Insulation
R19 to R38. Electric FAF Heating System w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 1.07 $2.11 $— $0.55 $0.15 $0.259 3.95 2.26 1
Single Family: Attic Insulation
R19 to R38. Heat pump. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.38 $0.89 $— $0.55 $0.15 $0.259 2.87 1.25 1
Single Family: Attic Insulation
R19 to R38. Heat pump. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.57 $1.33 $— $0.55 $0.15 $0.259 3.57 1.72 1
Single Family: Attic Insulation
R19 to R38. Heat pump. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.58 $1.36 $— $0.55 $0.15 $0.259 3.61 1.75 1
Single
Family: Attic Insulation
R19 to R38. Heat pump.
Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.60 $1.41 $— $0.55 $0.15 $0.259 3.68 1.80 1
Single Family: Attic Insulation
R19 to R38. Heat pump. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R38 ft2 ENRes_SF_HeatPump 45 80% 0.76 $1.78 $— $0.55 $0.15 $0.259 4.10 2.13 1
Single Family: Attic Insulation
R19 to R38. Zonal Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.65 $1.28 $— $0.55 $0.15 $0.259 3.22 1.60 1
Single
Family: Attic Insulation
R19 to R38. Zonal
Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.59 $1.16 $— $0.55 $0.15 $0.259 3.07 1.49 1
Single Family: Attic Insulation
R19 to R38. Zonal Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R38 ft2 ENRes_SF_Heater 45 80% 0.79 $1.57 $— $0.55 $0.15 $0.259 3.52 1.85 1
Single Family: Attic Insulation
R19 to R49. Average electric heating system w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.69 $1.35 $— $0.55 $0.15 $0.259 3.30 1.67 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 37
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R19 to R49. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.96 $1.89 $— $0.55 $0.15 $0.259 3.79 2.10 1
Single Family: Attic Insulation
R19 to R49. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.96 $1.89 $— $0.55 $0.15 $0.259 3.79 2.10 1
Single Family: Attic Insulation
R19 to R49. Average electric heating system w/o CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.96 $1.89 $— $0.55 $0.15 $0.259 3.79 2.10 1
Single Family: Attic Insulation
R19 to R49. Average electric heating system w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 1.16 $2.29 $— $0.55 $0.15 $0.259 4.07 2.38 1
Single Family: Attic Insulation
R19 to R49. Average Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.76 $1.77 $— $0.55 $0.15 $0.259 4.09 2.13 1
Single Family: Attic Insulation
R19 to R49. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.99 $2.31 $— $0.55 $0.15 $0.259 4.55 2.54 1
Single
Family: Attic Insulation
R19 to R49. Average
Heating System w/ CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 1.00 $2.34 $— $0.55 $0.15 $0.259 4.58 2.57 1
Single Family: Attic Insulation
R19 to R49. Average Heating System w/ CAC. Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 1.03 $2.41 $— $0.55 $0.15 $0.259 4.62 2.61 1
Single Family: Attic Insulation
R19 to R49. Average Heating System w/ CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 1.19 $2.79 $— $0.55 $0.15 $0.259 4.86 2.86 1
Single
Family: Attic Insulation
R19 to R49. Electric
FAF Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.89 $2.07 $— $0.55 $0.15 $0.259 4.37 2.37 1
Single Family: Attic Insulation
R19 to R49. Electric FAF Heating System w/ CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 1.15 $2.70 $— $0.55 $0.15 $0.259 4.81 2.81 1
Single Family: Attic Insulation
R19 to R49. Electric FAF Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.81 $1.61 $— $0.55 $0.15 $0.259 3.56 1.89 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 38 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Attic Insulation
R19 to R49. Electric FAF Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 1.11 $2.18 $— $0.55 $0.15 $0.259 4.00 2.31 1
Single Family: Attic Insulation
R19 to R49. Electric FAF Heating System w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 1.32 $2.60 $— $0.55 $0.15 $0.259 4.23 2.57 1
Single Family: Attic Insulation
R19 to R49. Heat pump. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.47 $1.10 $— $0.55 $0.15 $0.259 3.23 1.48 1
Single Family: Attic Insulation
R19 to R49. Heat pump. Heating Zone 2 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.70 $1.63 $— $0.55 $0.15 $0.259 3.94 2.00 1
Single Family: Attic Insulation
R19 to R49. Heat pump. Heating Zone 2 Cooling Zone 2
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.71 $1.67 $— $0.55 $0.15 $0.259 3.99 2.04 1
Single Family: Attic Insulation
R19 to R49. Heat pump. Heating Zone 2 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.74 $1.73 $— $0.55 $0.15 $0.259 4.05 2.09 1
Single
Family: Attic Insulation
R19 to R49. Heat pump.
Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.93 $2.18 $— $0.55 $0.15 $0.259 4.46 2.45 1
Single Family: Attic Insulation
R19 to R49. Zonal Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_HeatPump 45 80% 0.80 $1.87 $— $0.55 $0.15 $0.259 4.19 2.21 1
Single Family: Attic Insulation
R19 to R49. Zonal Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 0.73 $1.43 $— $0.55 $0.15 $0.259 3.39 1.74 1
Single
Family: Attic Insulation
R19 to R49. Zonal
Heating System w/o CAC. Heating Zone 3 Cooling Zone 1
Attic Insulation R19 to R49 ft2 ENRes_SF_Heater 45 80% 1.16 $2.30 $— $0.55 $0.15 $0.259 4.07 2.38 1
Single Family: Floor Insulation
R0 to R30. Electric FAF Heating System w/ CAC. Heating Zone 1 Cooling Zone 3
Floor Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 1.48 $3.47 $— $0.84 $0.50 $0.259 3.14 2.40 1
Single Family: Floor Insulation
R0 to R30. Electric FAF Heating System w/ CAC. Heating Zone 3 Cooling Zone 1
Floor Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 2.37 $5.54 $— $0.84 $0.50 $0.259 3.98 3.20 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 39
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Floor Insulation
R0 to R30. Electric FAF Heating System w/o CAC. Heating Zone 1
Floor Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 1.53 $3.02 $— $0.84 $0.50 $0.259 2.69 2.07 1
Single Family: Floor Insulation
R0 to R30. Electric FAF Heating System w/o CAC. Heating Zone 2
Floor Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 2.00 $3.94 $— $0.84 $0.50 $0.259 3.10 2.45 1
Single Family: Floor Insulation
R0 to R30. Electric FAF Heating System w/o CAC. Heating Zone 3
Floor Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 2.42 $4.77 $— $0.84 $0.50 $0.259 3.39 2.73 1
Single Family: Floor Insulation
R0 to R30. Heat Pump. Heating Zone 1 Cooling Zone 3.
Floor Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 0.61 $1.42 $— $0.84 $0.50 $0.259 1.72 1.22 1
Single Family: Floor Insulation
R0 to R30. Heat Pump. Heating Zone 2 Cooling Zone 2.
Floor Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 0.97 $2.27 $— $0.84 $0.50 $0.259 2.41 1.77 1
Single Family: Floor Insulation
R0 to R30. Heat Pump. Heating Zone 2 Cooling Zone 3.
Floor Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 0.97 $2.27 $— $0.84 $0.50 $0.259 2.42 1.78 1
Single
Family: Floor Insulation
R0 to R30. Heat Pump.
Heating Zone 3 Cooling Zone 1.
Floor
Insulation R0 to R30
ft2 ENRes_SF_HeatPump 45 80% 1.33 $3.11 $— $0.84 $0.50 $0.259 2.95 2.23 1
Single Family: Floor Insulation
R0 to R30. Zonal Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Floor Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 1.46 $2.88 $— $0.84 $0.50 $0.259 2.62 2.00 1
Single Family: Floor Insulation
R0 to R30. Zonal Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Floor Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 1.91 $3.77 $— $0.84 $0.50 $0.259 3.03 2.38 1
Single
Family: Floor Insulation
R0 to R30. Zonal
Heating System w/o CAC. Heating Zone 3 Cooling Zone 1
Floor
Insulation R0 to R30
ft2 ENRes_SF_Heater 45 80% 2.31 $4.55 $— $0.84 $0.50 $0.259 3.32 2.66 1
Single Family: Wall Insulation
R0 to R11. Electric FAF Heating System w/o CAC. Heating Zone 2 Cooling Zone 2
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 2.43 $4.80 $— $2.43 $0.50 $0.259 3.40 1.44 1
Single Family: Wall Insulation
R0 to R11. Electric FAF Heating System. Heating Zone 1
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 1.80 $3.55 $— $2.43 $0.50 $0.259 2.94 1.13 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 40 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Wall Insulation
R0 to R11. Electric FAF Heating System. Heating Zone 3
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 2.94 $5.80 $— $2.43 $0.50 $0.259 3.68 1.65 1
Single Family: Wall Insulation
R0 to R11. Heat Pump . Heating Zone 1 Cooling Zone 3
Wall Insulation R0 to R11 ft2 ENRes_SF_HeatPump 45 80% 0.95 $2.23 $— $2.43 $0.50 $0.259 2.39 0.78 1, 2
Single Family: Wall Insulation
R0 to R11. Heat Pump . Heating Zone 2 Cooling Zone 2
Wall Insulation R0 to R11 ft2 ENRes_SF_HeatPump 45 80% 1.53 $3.59 $— $2.43 $0.50 $0.259 3.20 1.18 1
Single Family: Wall Insulation
R0 to R11. Heat Pump. Heating Zone 3 Wall Insulation R0 to R11 ft2 ENRes_SF_HeatPump 45 80% 2.12 $4.96 $— $2.43 $0.50 $0.259 3.78 1.53 1
Single Family: Wall Insulation
R0 to R11. Zonal Heating System w/o CAC. Heating Zone 1 Cooling Zone 3
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 1.60 $3.15 $— $2.43 $0.50 $0.259 2.76 1.02 1
Single Family: Wall Insulation
R0 to R11. Zonal Heating System w/o CAC. Heating Zone 2 Cooling Zone 3
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 2.13 $4.20 $— $2.43 $0.50 $0.259 3.20 1.30 1
Single
Family: Wall Insulation
R0 to R11. Zonal
Heating System. Heating Zone 3
Wall Insulation R0 to R11 ft2 ENRes_SF_Heater 45 80% 2.57 $5.07 $— $2.43 $0.50 $0.259 3.48 1.50 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 29.63 $69.28 $— $23.71 $2.50 $0.259 5.45 2.04 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 16.92 $39.56 $— $23.71 $2.50 $0.259 4.60 1.33 1
Single Family: Window
Single Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 36.61 $85.60 $— $23.71 $2.50 $0.259 5.72 2.37 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 41
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Window
Double Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 21.16 $49.48 $— $23.71 $2.50 $0.259 4.96 1.59 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 29.62 $69.26 $— $23.71 $2.50 $0.259 5.45 2.04 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 16.85 $39.40 $— $23.71 $2.50 $0.259 4.59 1.32 1
Single Family: Window
Single Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 35.75 $83.59 $— $23.71 $2.50 $0.259 5.69 2.33 1
Single
Family: Window
Double Pane to Class
30: Heating Zone 3: Cooling Zone 1 (Zonal Heating System)
WINDOW
CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 20.57 $48.10 $— $23.71 $2.50 $0.259 4.92 1.55 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 33.73 $78.87 $— $23.71 $2.50 $0.259 5.62 2.24 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 19.16 $44.80 $— $23.71 $2.50 $0.259 4.80 1.47 1
Single Family: Window
Single Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 40.98 $95.82 $— $23.71 $2.50 $0.259 5.85 2.55 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 42 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Window
Double Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 23.56 $55.09 $— $23.71 $2.50 $0.259 5.12 1.72 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 22.95 $53.66 $— $23.71 $2.50 $0.259 5.08 1.69 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 1 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 13.38 $31.29 $— $23.71 $2.50 $0.259 4.20 1.09 1
Single Family: Window
Single Pane to Class 30: Heating Zone 3: Cooling Zone 1 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 31.10 $72.72 $— $23.71 $2.50 $0.259 5.51 2.11 1
Single
Family: Window
Double Pane to Class
30: Heating Zone 3: Cooling Zone 1 (Heat Pump Heating System)
WINDOW
CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 18.35 $42.91 $— $23.71 $2.50 $0.259 4.73 1.42 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 30.14 $70.47 $— $23.71 $2.50 $0.259 5.47 2.07 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 17.44 $40.78 $— $23.71 $2.50 $0.259 4.65 1.36 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 30.13 $70.45 $— $23.71 $2.50 $0.259 5.47 2.07 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 43
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 17.37 $40.61 $— $23.71 $2.50 $0.259 4.64 1.36 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 34.24 $80.06 $— $23.71 $2.50 $0.259 5.63 2.26 1
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 19.68 $46.02 $— $23.71 $2.50 $0.259 4.85 1.50 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 2 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 23.46 $54.85 $— $23.71 $2.50 $0.259 5.12 1.72 1
Single
Family: Window
Double Pane to Class
30: Heating Zone 2: Cooling Zone 2 (Heat Pump Heating System)
WINDOW
CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 13.89 $32.48 $— $23.71 $2.50 $0.259 4.26 1.13 1
Single Family: Window
Single Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 22.47 $52.54 $— $23.71 $2.50 $0.259 5.05 1.66 1
Single Family: Window
Double Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 13.31 $31.12 $— $23.71 $2.50 $0.259 4.19 1.09 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 30.86 $72.16 $— $23.71 $2.50 $0.259 5.50 2.10 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 44 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Average Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 18.15 $42.44 $— $23.71 $2.50 $0.259 4.71 1.40 1
Single Family: Window
Single Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 23.36 $54.62 $— $23.71 $2.50 $0.259 5.11 1.71 1
Single Family: Window
Double Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 13.74 $32.13 $— $23.71 $2.50 $0.259 4.24 1.12 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Zonal Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 30.85 $72.13 $— $23.71 $2.50 $0.259 5.50 2.10 1
Single
Family: Window
Double Pane to Class
30: Heating Zone 2: Cooling Zone 3 (Zonal Heating System)
WINDOW
CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 18.08 $42.27 $— $23.71 $2.50 $0.259 4.71 1.40 1
Single Family: Window
Single Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 26.14 $61.12 $— $23.71 $2.50 $0.259 5.27 1.86 1
Single Family: Window
Double Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 15.27 $35.70 $— $23.71 $2.50 $0.259 4.43 1.22 1
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 34.96 $81.74 $— $23.71 $2.50 $0.259 5.66 2.29 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 45
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unitf Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Single Family: Window
Double Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Electric FAF Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 20.39 $47.68 $— $23.71 $2.50 $0.259 4.90 1.54 1
Single Family: Window
Single Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 14.76 $34.51 $— $23.71 $2.50 $0.259 4.37 1.19 1
Single Family: Window
Double Pane to Class 30: Heating Zone 1: Cooling Zone 3 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 9.27 $21.68 $— $23.71 $2.50 $0.259 3.54 0.79 1, 2
Single Family: Window
Single Pane to Class 30: Heating Zone 2: Cooling Zone 3 (Heat Pump Heating System)
WINDOW CL30 Prime Window Replacement of Single Pane Base
ft2 ENRes_SF_HeatPump 45 80% 24.18 $56.54 $— $23.71 $2.50 $0.259 5.16 1.76 1
Single
Family: Window
Double Pane to Class
30: Heating Zone 2: Cooling Zone 3 (Heat Pump Heating System)
WINDOW
CL30 Prime Window Replacement of Double Pane Base
ft2 ENRes_SF_HeatPump 45 80% 14.60 $34.14 $— $23.71 $2.50 $0.259 4.35 1.75 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives. Based on 2013 median customer costs.
f Properly sealed ducts required for the program. If additional air sealing and duct sealing was required, an additional incentive of $0.50/ln. ft. was paid.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives). i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResSFWx_v2_5_IdahoPower_withCAC_ByCoolingZone.xlsm. 2011.
2 Measure combination not cost-effective. Will be monitored in 2014.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 46 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 47
Home Products Program
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 108,887 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 296,628 I Utility Cost Test ............................. $ 686,674 $ 405,515 1.69
Total Utility Cost ................................................................................................ $ 405,515 P Total Resource Cost Test .............. 1,365,047 608,333 2.24
Ratepayer Impact Measure Test ... 686,674 995,008 0.69
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 550,151 M Participant Cost Test ..................... 1,881,461 550,151 3.42

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 885,980 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 8,613,318 $ 858,342 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 858,342 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 736,866 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ 847,967 NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%
Notes: Non-energy benefits include the NPV of avoided gas, water, and detergent savings for ENERGY STAR clothes washers and low-flow showerheads. Gas savings based on RTF’s assumptions of therms saved per year.
Clothes washers removed from the program in March 2013 due to the measure as currently offered in the program not being cost-effective.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 48 Demand-Side Management 2013 Annual Report

Year:2013 Program: Home Products Program Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)e
Gross Incremental Participant Costf Incentive/ Unit Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Clothes Washer ENERGY STAR clothes washer, any MEF, any DHW, any dryer
Baseline clothes washers
Washer ENRes_SF_Washer 14 80% 41.00 $44.99 $206.88 $78.61 $50.00 $0.366 0.55 2.29 1, 2
Clothes Washer ENERGY STAR clothes washer MEF of 2.4 or higher and WF of 4 or
lower, any DHW, any dryer
Baseline clothes washers
Washer ENRes_SF_Washer 14 80% 70.00 $76.81 $306.34 $90.14 $50.00 $0.366 0.81 2.84 1, 2
Clothes Washer ENERGY STAR clothes washer MEF of 3.2 or higher and WF of 2.9 or lower, any DHW, any dryer
Baseline clothes washers
Washer ENRes_SF_Washer 14 80% 121.00 $132.77 $455.39 $270.15 $50.00 $0.366 1.13 1.74 1, 2
Refrigerator ENERGY STAR refrigerator: any Baseline refrigerator
Refrigerator ENRes_SF_Refrigerator 17 80% 26.00 $31.95 $— $14.08 $30.00 $0.366 0.65 0.95 3, 4
Refrigerator ENERGY STAR Refrigerator: Bottom freezer w/ice thru door
Baseline refrigerator Refrigerator ENRes_SF_Refrigerator 17 80% 16.00 $19.66 $— $6.52 $30.00 $0.366 0.44 0.92 3, 4
Refrigerator ENERGY STAR Refrigerator: Bottom freezer w/o ice thru door
Baseline refrigerator Refrigerator ENRes_SF_Refrigerator 17 80% 18.00 $22.12 $— $6.25 $30.00 $0.366 0.48 1.01 3
Refrigerator ENERGY STAR Refrigerator: Side-by-side w/ice thru door
Baseline refrigerator
Refrigerator ENRes_SF_Refrigerator 17 80% 18.00 $22.12 $— $15.89 $30.00 $0.366 0.48 0.70 3, 4
Refrigerator ENERGY STAR Refrigerator: Side-by-side w/o ice thru door
Baseline refrigerator Refrigerator ENRes_SF_Refrigerator 17 80% 21.00 $25.81 $— $24.78 $30.00 $0.366 0.55 0.62 3, 4
Refrigerator ENERGY STAR Refrigerator: Top freezer w/ice thru door
Baseline refrigerator
Refrigerator ENRes_SF_Refrigerator 17 80% 24.00 $29.50 $— $10.50 $30.00 $0.366 0.61 1.02 3
Refrigerator ENERGY STAR Refrigerator: Top freezer w/o ice thru door
Baseline refrigerator
Refrigerator ENRes_SF_Refrigerator 17 80% 49.00 $60.22 $— $18.10 $30.00 $0.366 1.00 1.25 3
Freezer ENERGY STAR freezer No tiers. any freezer Baseline freezer freezer ENRes_SF_Freezer 22 80% 40.00 $60.73 $— $4.31 $20.00 $0.366 1.40 2.20 5
Freezer ENERGY STAR Freezer (no tiers): Chest, any defrost
Baseline freezer freezer ENRes_SF_Freezer 22 80% 29.00 $44.03 $— $3.41 $20.00 $0.366 1.15 2.03 5
Freezer ENERGY STAR Freezer
(no tiers): Upright, automatic defrost
Baseline
freezer
freezer ENRes_SF_Freezer 22 80% 56.00 $85.03 $— $5.80 $20.00 $0.366 1.68 2.33 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 49
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)e
Gross Incremental Participant Costf Incentive/ Unit Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Freezer ENERGY STAR Freezer (no tiers): Upright, manual defrost
Baseline freezer freezer ENRes_SF_Freezer 22 80% 28.00 $42.51 $— $2.90 $20.00 $0.366 1.12 2.05 5
Freezer ENERGY STAR Freezer (no tiers): any upright freezer
Baseline freezer freezer ENRes_SF_Freezer 22 80% 47.00 $71.36 $— $4.94 $20.00 $0.366 1.53 2.27 5
Low-flow showerhead Low-flow showerhead 2.0 gpm any shower any water heating retail
Showerhead 2.2 gpm or higher
showerhead ENRes_SF_WtrHtr 10 80% 66.78 $50.28 $91.61 $27.61 $7.00 $0.005 5.48 4.76 6
Low-flow showerhead Low-flow showerhead 1.75 gpm any shower any water heating retail
Showerhead 2.2 gpm or higher
showerhead ENRes_SF_WtrHtr 10 80% 99.77 $75.13 $134.42 $27.61 $7.00 $0.005 8.00 6.98 6
Low-flow showerhead Low-flow showerhead 1.5 gpm any shower any water heating retail
Showerhead 2.2 gpm or higher
showerhead ENRes_SF_WtrHtr 10 80% 129.12 $97.22 $107.91 $27.61 $7.00 $0.005 10.14 8.88 6
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Sum of NPV of avoided cost of gas, water, and detergent savings.
f Incremental participant cost prior to customer incentives.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResClothesWasherSF_v4.0.xls. Any DHW, Any Dryer. 2013. Adjusted savings by changing Electric Water Heating saturation from 55% to 52% to match IPC mix.
2 Measure not cost-effective. Measure removed from the program in 2013.
3 RTF. ResRefrigerator_v3_1.xls. 2013.
4 Measure not cost-effective. Will be monitored in 2014.
5 RTF. ResFreezer_v2_2.xlsm. 2012.
6 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 50 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 51
Rebate Advantage
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 28,770 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 32,000 I Utility Cost Test ............................. $ 327,841 $ 60,770 5.39
Total Utility Cost ................................................................................................ $ 60,770 P Total Resource Cost Test .............. 327,841 86,306 3.80
Ratepayer Impact Measure Test ... 327,841 361,407 0.91
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 63,920 M Participant Cost Test ..................... 407,795 63,920 6.38

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 269,891 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 3,849,999 $ 409,802 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 409,802 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 375,795 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
Line Losses ................................................................................................. 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 52 Demand-Side Management 2013 Annual Report
Year:2013 Program: Rebate Advantage Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
ENERGY STAR® manufactured home
New ENERGY STAR Manufactured Home with Electric FAF: Heating Zone 1
Manufactured home built to Housing and Urban Development (HUD) code.
Home ENRes_MH_Heater 26 80% 5,420.00 $7,790.13 $— $1,567.49 $1,000.00 $0.107 3.95 3.07 1
ENERGY
STAR manufactured home
New ENERGY STAR
Manufactured Home with Electric FAF: Heating Zone 2
Manufactured
home built to HUD code.
Home ENRes_MH_Heater 27 80% 6,847.00 $10,092.11 $— $1,567.49 $1,000.00 $0.107 4.67 3.70 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Electric FAF: Heating Zone 3
Manufactured home built to HUD code.
Home ENRes_MH_Heater 27 80% 8,057.00 $11,875.59 $— $1,567.49 $1,000.00 $0.107 5.11 4.11 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 1 Cooling Zone 3
Manufactured home built to HUD code.
Home Res_HVAC 23 80% 3,254.00 $5,925.77 $— $1,567.49 $1,000.00 $0.107 3.52 2.63 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 2 Cooling Zone 1
Manufactured home built to HUD code.
Home Res_HVAC 25 80% 4,346.00 $8,345.54 $— $1,567.49 $1,000.00 $0.107 4.56 3.48 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 2 Cooling Zone 2
Manufactured home built to HUD code.
Home Res_HVAC 25 80% 4,390.00 $8,430.03 $— $1,567.49 $1,000.00 $0.107 4.59 3.51 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 2 Cooling Zone 3
Manufactured home built to HUD code.
Home Res_HVAC 25 80% 4,472.00 $8,587.50 $— $1,567.49 $1,000.00 $0.107 4.65 3.56 1
ENERGY STAR manufactured home
New ENERGY STAR Manufactured Home with Heat Pump: Heating Zone 3 Cooling Zone 1
Manufactured home built to HUD code.
Home Res_HVAC 26 80% 5,516.00 $10,848.13 $— $1,567.49 $1,000.00 $0.107 5.47 4.25 1
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 53
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. NewMH_EStar_EcoRated_v1_3.xls. 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 54 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 55
See ya later, refrigerator®
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 490,144 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 98,910 I Utility Cost Test ............................. $ 723,695 $ 589,054 1.23
Total Utility Cost ................................................................................................ $ 589,054 P Total Resource Cost Test .............. 723,695 589,054 1.23
Ratepayer Impact Measure Test ... 723,695 1,257,050 0.58
Measure Equipment and Installation (Incremental Participant Cost) .................... $ — M Participant Cost Test ..................... N/A N/A N/A

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 1,442,344 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 8,394,736 $ 723,695 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 723,695 S Participant Cost Test .......................... N/A N/A

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 667,996 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 100.00%
Average Customer Segment Rate/kWh ....................................................... $0.086
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 56 Demand-Side Management 2013 Annual Report
Year:2013 Program: See ya later, refrigerator® Market Segment: Residential Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Freezer Recycling Freezer removal and decommissioning Freezer ENRes_SF_Freezer 5 100% 478.00 $192.09 $— $— $30.00 $0.340 1.00 1.00 1
Refrigerator Recycling Refrigerator removal and decommissioning Refrigerator ENRes_SF_SecRef 7 100% 424.00 $232.35 $— $— $30.00 $0.340 1.33 1.33 1
a Average measure life.
b No Net-to-Gross (NTG) percentage. Deemed savings from RTF includes realization rates.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e No participant cost.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. ResFridgeFreezeDecommissioning_v2.5.xlsm. 2012.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 57
Weatherization Assistance for Qualified Customers
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 247,587 Test Benefit Cost Ratio
CAP Agency Payments ....................................................................................... 1,144,090 Utility Cost Test ............................. $ 1,310,726 $ 1,380,671 0.95
Total Program Expenses ................................................................................... $ 1,391,677 Total Resource Cost Test .............. 1,502,827 2,041,014 0.74
Less: 2013 Evaluations Expenses (Unamortized Years 2 & 3) (48,089) Ratepayer Impact Measure Test ... 1,310,726 2,329,919 0.56
Total Utility Cost ................................................................................................ $ 1,343,588 P Participant Cost Test ..................... N/A N/A N/A

Idaho Power Indirect Overhead Expense Allocation—2.76% $ 37,083 OH
Additional State Funding 660,343 M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P + OH
2013 Annual Gross Energy (kWh) ............................................ 681,736 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + OH + M
NPV Cumulative Energy (kWh) ................................................. 9,737,706 $ 1,191,569 Ratepayer Impact Measure Test ........ = S * NTG = P + OH +(B * NTG)
10% Credit (Northwest Power Act) ........................................... 119,157 Participant Cost Test .......................... N/A N/A
Total Electric Savings ................................................................ $ 1,310,726 S

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 949,247 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. Net-to-Gross (NTG) .................................................................................... 100.00%
Health and Safety ............................................................... 163,713 Average Customer Segment Rate/kWh ....................................................... $0.086
Repair ................................................................................. 28,388 Line Losses ................................................................................................. 10.90%
Other .................................................................................. —
Non-Energy Benefits Total ..................................................... $ 192,101 NEB
Notes: Savings based on average realized savings of 2,684 kWh per home. Savings from the billing analysis of the 2011 projects.
Program cost-effectiveness incorporated Idaho Public Utilities Commission (IPUC) staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Claimed 100% of savings; increased NTG to 100%; added a 10% conservation preference adder; health, safety, and repair non-energy benefits; amortized evaluation expenses over a three-year period; and allocation of indirect overhead expenses.
No customer participant costs. Costs shown are from the DOE state weatherization assistance program.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 58 Demand-Side Management 2013 Annual Report
This page left blank intentionally.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 59
Weatherization Solutions for Eligible Customers
Segment: Residential
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 232,695 Test Benefit Cost Ratio
Weatherization LLC Payments ............................................................................ 1,035,096 Utility Cost Test ............................. $ 582,780 $ 1,253,366 0.46
Total Program Expenses ................................................................................... $ 1,267,791 Total Resource Cost Test .............. 658,345 1,253,366 0.53
Less: 2013 Evaluations Expenses (Unamortized Years 2 & 3) (48,089) Ratepayer Impact Measure Test ... 582,780 1,675,424 0.35
Total Utility Cost ................................................................................................ $ 1,219,702 P Participant Cost Test ..................... N/A N/A N/A

Idaho Power Indirect Overhead Expense Allocation—2.76% $ 33,664 OH
Additional State Funding — M

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P + OH
2013 Annual Gross Energy (kWh) ............................................ 303,116 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + OH + M
NPV Cumulative Energy (kWh) ................................................. 4,329,615 $ 529,800 Ratepayer Impact Measure Test ........ = S * NTG = P + OH +(B * NTG)
10% Credit (Northwest Power Act) ........................................... 52,980 Participant Cost Test .......................... N/A N/A
Total Electric Savings ................................................................ $ 582,780 S

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 422,058 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. Net-to-Gross (NTG) .................................................................................... 100.00%
Health and Safety ............................................................... 65,742 Average Customer Segment Rate/kWh ....................................................... $0.086
Repair ................................................................................. 9,812 Line Losses ................................................................................................. 10.90%
Other .................................................................................. —
Non-Energy Benefits Total ..................................................... $ 75,565 NEB
Notes: Savings based on average realized savings of 1,826 kWh per home. Savings from the billing analysis of the 2011 projects.
Program cost-effectiveness incorporated IPUC staff recommendations from Case No. GNR-E-12-01. Recommendations include:
Increased NTG to 100%; added a 10% conservation preference adder; health, safety, and repair non-energy benefits; amortized evaluation expenses over a three-year period; and allocation of indirect overhead expenses.
No customer participant costs.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 60 Demand-Side Management 2013 Annual Report
This page left blank intentionally.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 61
Building Efficiency
Segment: Commercial
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 356,623 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 1,150,412 I Utility Cost Test ............................. $ 8,255,178 $ 1,507,035 5.48
Total Utility Cost ................................................................................................ $ 1,507,035 P Total Resource Cost Test .............. 8,255,178 2,535,381 3.26
Ratepayer Impact Measure Test ... 8,255,178 6,322,879 1.31
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 2,435,845 M Participant Cost Test ..................... 7,170,218 2,435,845 2.94

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 10,988,934 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 106,839,919 $ 10,318,972 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 10,318,972 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 6,019,806 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.057
Line Losses ................................................................................................. 10.90%

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 62 Demand-Side Management 2013 Annual Report
Year:2013 Program: Building Efficiency Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Lighting Controls Interior light load reduction:10–19% below code
Code standards ft2 ENComm_InsLt 11 96% 0.38 $0.33 $— $0.05 $0.05 $0.032 5.17 5.17 1
Lighting Controls Interior light load reduction - 20% or more below code
Code standards ft2 ENComm_InsLt 11 96% 1.09 $0.96 $— $0.10 $0.15 $0.032 4.98 6.73 1
Lighting Controls Exterior light load reduction: 15% or more below code
Code standards kW IPC_Outdoor Lighting 11 96% 4,059.00 $2,644.99 $— $205.00 $200.00 $0.032 7.70 7.59 2
Lighting
Controls
Daylight photo controls Code
standards
Square
Feet
ENComm_InsLt 8 96% 0.61 $0.40 $— $0.25 $0.25 $0.032 1.41 1.41 3
Lighting Controls Occupancy sensors Code standards Sensor ENComm_InsLt 8 96% 289.99 $189.85 $— $77.00 $25.00 $0.032 5.32 2.16 3
Sign Lighting High efficiency exit signs Code standards Signs IPC_8760 16 96% 333.00 $379.59 $— $31.52 $7.50 $0.032 20.07 8.84 3
A/C & Heat Pump Units Premium Efficiency HVAC unit Code standards Ton ENComm_HVAC 15 80% 386.72 $469.49 $— $122.22 $50.00 $0.032 6.02 3.13 1
A/C & Heat Pump Units Additional HVAC Unit Efficiency bonus Code standards Ton ENComm_HVAC 15 80% 181.78 $220.69 $— $81.50 $25.00 $0.032 5.73 2.32 1
A/C & Heat Pump Units Efficient Chillers Code standards Ton ENComm_Cooling 15 80% 154.28 $207.42 $— $75.00 $20.00 $0.032 6.65 2.41 2
Economizers Air side economizers Code standards Ton ENComm_Cooling 15 80% 300.00 $403.34 $— $170.00 $75.00 $0.032 3.81 2.01 3
Reflective Roofing Reflective roof coating Code standards ft2 ENComm_Cooling 15 80% 0.41 $0.55 $— $0.35 $0.05 $0.032 6.99 1.45 3
Efficient Windows High-performance windows Code standards ft2 ENComm_HVAC 30 80% 1.01 $1.99 $— $0.74 $0.50 $0.032 3.00 2.20 3
Automated Control Systems
Energy management control systems Code standards ft2 ENComm_HVAC 14 96% 1.24 $1.42 $— $1.00 $0.30 $0.032 4.02 1.35 3
Automated Control Systems
Demand controlled ventilation Code standards Ft3per Minute ENComm_HVAC 10 96% 1.31 $1.12 $— $0.60 $0.50 $0.032 1.98 1.68 3
Variable Speed Controls
Variable speed drives Code standards HP ENComm_HVAC 15 96% 985.02 $1,195.84 $— $187.00 $60.00 $0.032 12.54 5.38 3
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives. f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 63
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Savings calculated from Idaho Power engineering estimates and research. Participant costs calculated based on 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 64 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 65
Custom Efficiency
Segment: Industrial
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 1,112,064 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 1,354,161 I Utility Cost Test ............................. $ 13,846,551 $ 2,466,225 5.61
Total Utility Cost ................................................................................................ $ 2,466,225 P Total Resource Cost Test .............. 13,846,551 5,413,798 2.56
Ratepayer Impact Measure Test ... 13,846,551 7,667,765 1.81
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 5,626,006 M Participant Cost Test ..................... 8,892,624 5,656,006 1.58

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 21,370,350 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 207,773,244 $ 20,067,465 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 20,067,465 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 7,538,463 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 69.00%
Average Customer Segment Rate/kWh ....................................................... $0.037
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. 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 66 Demand-Side Management 2013 Annual Report
Year:2013 Program: Custom Efficiency—Green Motors Market Segment: Industrial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 15HP
Standard rewind practice
Motor MF_Motors 8 69% 601.00 $377.80 $— $154.35 $30.00 $0.050 4.34 1.79 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 20HP
Standard rewind practice
Motor MF_Motors 8 69% 804.00 $505.41 $— $172.21 $40.00 $0.050 4.35 2.03 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 25HP
Standard rewind practice
Motor MF_Motors 8 69% 1,052.00 $661.31 $— $196.76 $50.00 $0.050 4.45 2.24 1
Green Motors
Program Rewind
Green Motors
Program Rewind: Motor size 30HP
Standard
rewind practice
Motor MF_Motors 8 69% 1,133.00 $712.23 $— $216.10 $60.00 $0.050 4.21 2.19 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 40HP
Standard rewind practice
Motor MF_Motors 8 69% 1,319.00 $829.15 $— $264.09 $80.00 $0.050 3.92 2.10 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 50HP
Standard rewind practice
Motor MF_Motors 8 69% 1,418.00 $891.39 $— $292.35 $100.00 $0.050 3.60 2.03 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 60HP
Standard rewind practice
Motor MF_Motors 9 69% 1,476.00 $1,037.42 $— $344.79 $120.00 $0.050 3.69 2.05 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 70HP
Standard rewind practice
Motor MF_Motors 9 69% 1,519.00 $1,067.64 $— $372.69 $150.00 $0.050 3.26 1.94 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 100HP
Standard rewind practice
Motor MF_Motors 9 69% 2,005.00 $1,409.23 $— $462.33 $200.00 $0.050 3.24 2.02 1
Green Motors Program
Rewind
Green Motors Program Rewind:
Motor size 125HP
Standard rewind
practice
Motor MF_Motors 8 69% 2,598.00 $1,633.16 $— $519.23 $250.00 $0.050 2.97 1.99 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 150HP
Standard rewind practice
Motor MF_Motors 8 69% 3,089.00 $1,941.81 $— $578.37 $300.00 $0.050 2.95 2.07 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 200HP
Standard rewind practice
Motor MF_Motors 8 69% 4,088.00 $2,569.80 $— $696.28 $400.00 $0.050 2.93 2.19 1
Green Motors
Program Rewind
Green Motors
Program Rewind: Motor size 250HP
Standard
rewind practice
Motor MF_Motors 9 69% 4,972.00 $3,494.60 $— $894.90 $500.00 $0.050 3.22 2.36 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 300HP
Standard rewind practice
Motor MF_Motors 9 69% 5,935.00 $4,171.45 $— $904.58 $600.00 $0.050 3.21 2.60 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 67
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 350HP
Standard rewind practice
Motor MF_Motors 9 69% 6,919.00 $4,863.06 $— $948.10 $700.00 $0.050 3.21 2.76 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 400HP
Standard rewind practice
Motor MF_Motors 9 69% 7,848.00 $5,516.01 $— $1,058.93 $800.00 $0.050 3.19 2.78 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 450HP
Standard rewind practice
Motor MF_Motors 9 69% 8,811.00 $6,192.86 $— $1,157.49 $900.00 $0.050 3.19 2.81 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 500HP
Standard rewind practice
Motor MF_Motors 9 69% 9,804.00 $6,890.80 $— $1,250.49 $1,000.00 $0.050 3.19 2.86 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 600HP
Standard rewind practice
Motor MF_Motors 7 69% 14,689.00 $8,119.94 $— $1,842.75 $1,200.00 $0.050 2.90 2.36 1
a Average measure life.
b Net-to-Gross (NTG) percentage. CPUC DEER NTFR Update Process for 2006-2007 Programs.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. IndGreenMotorRewind_v2_0.xlsm. 2013.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 68 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 69
Easy Upgrades
Segment: Commercial
2013 Program Results

Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ....................................................................................... $ 985,274 Test Benefit Cost Ratio
Program Incentives .............................................................................................. 2,374,516 I Utility Cost Test ............................. $ 15,822,291 $ 3,359,790 4.71
Total Utility Cost ................................................................................................ $ 3,359,790 P Total Resource Cost Test .............. 15,822,291 6,062,874 2.61
Ratepayer Impact Measure Test ... 15,822,291 12,590,081 1.26
Measure Equipment and Installation (Incremental Participant Cost) .................... $ 5,753,371 M Participant Cost Test ..................... 13,912,379 5,753,371 2.42

Net Benefit Inputs (NPV) Ref Benefits and Costs Included in Each Test
Resource Savings Utility Cost Test .................................. = S * NTG = P
2013 Annual Gross Energy (kWh) ............................................ 21,061,946 Total Resource Cost Test ................... = (S + NUI + NEB) * NTG = P + ((M-I)*NTG)
NPV Cumulative Energy (kWh) ................................................. 204,774,786 $ 19,777,864 Ratepayer Impact Measure Test ........ = S * NTG = P + (B * NTG)
Total Electric Savings ................................................................ $ 19,777,864 S Participant Cost Test .......................... = B + I + NUI + NEB = M

Participant Bill Savings Assumptions for Levelized Calculations
NPV Cumulative Participant Savings ........................................ $ 11,537,863 B Discount Rate
Nominal (WACC) ..................................................................................... 7.00%
Other Benefits Real ((1 + WACC) / (1 + Escalation)) – 1 ................................................. 3.88%
Non-Utility Rebates/Incentives .................................................. $ — NUI Escalation Rate ........................................................................................... 3.00%
Non-Energy Benefits ................................................................. $ — NEB Net-to-Gross (NTG) .................................................................................... 80.00%
Average Customer Segment Rate/kWh ....................................................... $0.057
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 70 Demand-Side Management 2013 Annual Report
Year:2013 Program: Easy Upgrades Market Segment: Commercial Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
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 ENComm_InsLt 11 96% 106.40 $93.68 $— $40.92 $8.00 $0.047 6.92 2.02 1
Standard T8s 1 lamp 4-ft T8 and electronic ballast 1 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 59.50 $52.39 $— $28.40 $12.00 $0.047 3.40 1.65 1
Standard T8s 1 or 2 lamp 4-ft T8s and electronic ballasts 2 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 108.50 $95.53 $— $37.60 $14.00 $0.047 4.80 2.20 1
Standard T8s 2 or 3 lamp 4-ft T8s and electronic ballast 3 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 176.75 $155.62 $— $54.45 $18.00 $0.047 5.68 2.44 1
Standard T8s 2, 3, or 4 lamp 4-ft T8s and electronic ballasts 4 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 236.83 $208.52 $— $59.83 $22.00 $0.047 6.04 2.88 1
Standard T8s 1 or 2 lamp 6-ft T8s and electronic ballast 1 or 2 Lamp 6-ft T12 Fixture ENComm_InsLt 12 96% 121.33 $115.61 $— $49.33 $14.00 $0.047 5.63 2.07 1
Standard T8s
1 or 2 lamp 6-ft T8s and electronic ballast (slimline & ho)
1 or 2 Lamp 6-ft T12HO/VHO Fixture ENComm_InsLt 12 96% 377.03 $359.24 $— $81.55 $14.00 $0.047 10.87 3.57 1
Standard T8s 1 or 2 lamp 8-ft T8s and electronic ballast 1 or 2 Lamp 8-ft T12 Fixture ENComm_InsLt 12 96% 116.67 $111.16 $— $58.47 $12.00 $0.047 6.10 1.72 1
Standard T8s 2, 3 or 4 lamp 8-ft T8s and electronic ballast 3 or 4 Lamp 8-ft T12 Fixture ENComm_InsLt 12 96% 262.50 $250.11 $— $101.66 $24.00 $0.047 6.61 2.17 1
Standard T8s
1 or 2 lamp 8-ft T8s and electronic ballast (slimline & ho)
1 or 2 Lamp 8-ft T12HO/VHO Fixture ENComm_InsLt 12 96% 525.91 $501.09 $— $67.57 $12.00 $0.047 13.10 5.34 1
Standard T8s
2, 3 or 4 lamp 8-ft T8s and electronic ballast (slimline & ho)
3 or 4 Lamp 8-ft T12HO/VHO Fixture ENComm_InsLt 12 96% 1,195.59 $1,139.17 $— $95.00 $24.00 $0.047 13.64 7.37 1
Standard T8s
2 or 4 lamp 4-ft T8s and electronic ballast
(tandem/retrofit)
1 or 2 Lamp 8-ft T12 Fixture ENComm_InsLt 11 96% 121.33 $106.83 $— $53.07 $22.00 $0.047 3.70 1.78 1
Standard T8s
2 or 4 lamp 4-ft T8s and electronic ballast (tandem/retrofit)
1 or 2 Lamp 8-ft T12HO/VHO Fixture ENComm_InsLt 11 96% 540.87 $476.20 $— $54.81 $30.00 $0.047 8.25 5.77 1
High performance T8s
1 lamp 4-ft hp T8 and electronic ballast 1 Lamp 4-ft T12 Fixture ENComm_InsLt 12 96% 80.50 $76.70 $— $62.98 $22.00 $0.047 2.86 1.13 1
High
performance T8s
1 or 2 lamp 4-ft hp T8s and electronic ballast 2 Lamp 4-ft T12 Fixture ENComm_InsLt 12 96% 129.86 $123.73 $— $60.13 $24.00 $0.047 3.95 1.83 1
High performance T8s
2 or 3 lamp 4-ft hp T8s and electronic ballast 3 Lamp 4-ft T12 Fixture ENComm_InsLt 12 96% 203.97 $194.35 $— $67.23 $32.00 $0.047 4.49 2.47 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 71
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
High performance T8s
2, 3, or 4 lamp 4-ft hp T8s and electronic ballast
4 Lamp 4-ft T12 Fixture ENComm_InsLt 12 96% 262.83 $250.43 $— $67.32 $34.00 $0.047 5.19 3.07 1
High performance T8s
2 or 4 lamp 4-ft hp T8s and electronic ballast (tandem/retrofit)
1 or 2 Lamp 8-ft T12 Fixture ENComm_InsLt 12 96% 171.07 $163.00 $— $68.86 $34.00 $0.047 3.72 2.07 1
High performance T8s
2 or 4 lamp 4-ft hp T8s and electronic ballast (tandem/retrofit)
1 or 2 Lamp 8-ft T12HO/VHO Fixture ENComm_InsLt 12 96% 567.38 $540.61 $— $74.54 $45.00 $0.047 7.24 5.19 1
T5 (Non-HO) 1 or 2 lamp 4-ft T5s and electronic ballast 1 or 2 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 102.67 $90.39 $— $50.30 $14.00 $0.047 4.61 1.62 1
T5 (Non-HO) 2, 3, or 4 lamp 4-ft T5s and electronic ballast 3 or 4 Lamp 4-ft T12 Fixture ENComm_InsLt 11 96% 185.50 $163.32 $— $90.34 $24.00 $0.047 4.79 1.63 1
T5/T8 high bay (new fixture)
4 lamp 4-ft T8s and electronic ballast Fixture (lamp & ballast) using ≥ 200 W
Fixture ENComm_InsLt 12 96% 574.58 $547.47 $— $153.91 $75.00 $0.047 5.15 2.96 1
T5/T8 high bay (new fixture)
6 lamp 4-ft T8s and electronic ballast or 2, 3, or 4 lamp 4-ft T5hos and electronic ballast
Fixture (lamp & ballast) using 200–399 W
Fixture ENComm_InsLt 12 96% 400.47 $381.57 $— $184.82 $75.00 $0.047 3.90 1.84 1
T5/T8 high bay (new fixture)
6 or 8 lamp 4-ft T8s and electronic ballast or 4 or 6 lamp 4-ft T5hos and electronic ballast
Fixture (lamp & ballast) using ≥ 400 W
Fixture ENComm_InsLt 12 96% 966.27 $920.68 $— $210.34 $110.00 $0.047 5.69 3.51 1
T5/T8 high bay (new fixture)
10 or 12 lamp 4-ft T8s
and electronic ballast or 8 or 10 lamp 4-ft T5hos and electronic ballast
Fixture (lamp &
ballast) 751–1,100 W
Fixture ENComm_InsLt 12 96% 2,366.70 $2,255.03 $— $386.65 $180.00 $0.047 7.43 4.42 1
T8/T5 HO–T8/T5HO relamp only
Lamp 4-ft Reduced Wattage HP T8 Fixture ENComm_InsLt 8 96% 84.00 $54.99 $— $15.20 $1.00 $0.047 10.67 2.84 1
T8/T5 HO–T8/T5HO relamp only
2 Lamp 4-ft Reduced Wattage HP T8 Fixture ENComm_InsLt 8 96% 137.12 $89.77 $— $22.83 $2.00 $0.047 10.21 3.03 1
T8/T5 HO–T8/T5HO relamp only
3 Lamp 4-ft Reduced Wattage HP T8 Fixture ENComm_InsLt 8 96% 107.80 $70.58 $— $31.62 $3.00 $0.047 8.40 1.91 1
T8/T5 HO–T8/T5HO relamp only
4 Lamp 4-ft Reduced Wattage HP T8 Fixture ENComm_InsLt 8 96% 96.25 $63.01 $— $37.83 $4.00 $0.047 7.10 1.48 1
T8/T5 HO–T8/T5HO relamp only
1 Lamp 4-ft Reduced Wattage T5 1 or 2 lamp 4-ft T5 Fixture ENComm_InsLt 8 96% 56.00 $36.66 $— $2.50 $1.00 $0.047 9.69 6.94 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 72 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
T8/T5 HO–T8/T5HO relamp only
2 Lamp 4-ft Reduced Wattage T5 2 or 3 or 4 lamp 4-ft T5 Fixture ENComm_InsLt 8 96% 119.00 $77.91 $— $5.00 $2.00 $0.047 9.85 7.14 1
T8/T5 HO–T8/T5HO relamp only
3 Lamp 4-ft Reduced Wattage T5 3 or 4 lamp 4-ft T5 Fixture ENComm_InsLt 8 96% 77.00 $50.41 $— $7.50 $3.00 $0.047 7.31 4.42 1
T8/T5 HO–T8/T5HO relamp only
4 Lamp 4-ft Reduced Wattage T5 4 lamp 4-ft T5 Fixture ENComm_InsLt 8 96% 42.00 $27.50 $— $10.00 $4.00 $0.047 4.42 2.25 1
T8/T5 HO–T8/T5HO relamp only
1 Lamp 4-ft Reduced Wattage T5HO 1 or 2 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 115.50 $75.62 $— $2.50 $1.00 $0.047 11.29 9.23 1
T8/T5 HO–T8/T5HO relamp only
2 Lamp 4-ft Reduced Wattage T5HO 2 or 3 or 4 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 243.83 $159.63 $— $5.00 $2.00 $0.047 11.39 9.38 1
T8/T5 HO–
T8/T5HO relamp only
3 Lamp 4-ft Reduced
Wattage T5HO
3 or 4 lamp 4-ft
T5HO
Fixture ENComm_InsLt 8 96% 154.00 $100.82 $— $7.50 $3.00 $0.047 9.45 6.65 1
T8/T5 HO–T8/T5HO relamp only
4 Lamp 4-ft Reduced Wattage T5HO 4 or 6 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 294.00 $192.48 $— $10.00 $4.00 $0.047 10.37 7.84 1
T8/T5 HO–T8/T5HO relamp only
6 Lamp 4-ft Reduced Wattage T5HO 6 or 8 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 308.00 $201.64 $— $15.00 $6.00 $0.047 9.45 6.65 1
T8/T5 HO–
T8/T5HO relamp only
8 Lamp 4-ft Reduced Wattage T5HO 8 or 10 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 379.75 $248.62 $— $20.00 $8.00 $0.047 9.23 6.39 1
T8/T5 HO–T8/T5HO relamp only
10 Lamp 4-ft Reduced Wattage T5HO 10 lamp 4-ft T5HO Fixture ENComm_InsLt 8 96% 213.50 $139.78 $— $25.00 $10.00 $0.047 6.70 3.90 1
T8/T5 HO–T8/T5HO relamp only
1 or 2 lamp 4-ft 28 watt T8 1 Lamp 4-ft 25 W T8 Fixture ENComm_InsLt 8 96% 78.94 $51.68 $— $15.20 $1.00 $0.047 10.53 2.71 1
T8/T5 HO–T8/T5HO relamp only
2 or 3 lamp 4-ft 28 watt T8 2 Lamp 4-ft 25 W T8 Fixture ENComm_InsLt 8 96% 85.63 $56.06 $— $21.42 $2.00 $0.047 8.93 2.18 1
T8/T5 HO–T8/T5HO relamp only
3 or 4 lamp 4-ft 28 watt T8 3 Lamp 4-ft 25 W T8 Fixture ENComm_InsLt 8 96% 102.75 $67.27 $— $31.62 $3.00 $0.047 8.25 1.83 1
T8/T5 HO–T8/T5HO relamp only
4 lamp 4-ft 28 watt T8 2 Lamp 4-ft 25 W T8 Fixture ENComm_InsLt 8 96% 190.17 $124.50 $— $25.42 $2.00 $0.047 10.93 3.58 1
T8/T5 HO–T8/T5HO relamp only
4 lamp 4-ft 28 watt T8 4 Lamp 4-ft 25 W T8 Fixture ENComm_InsLt 8 96% 81.67 $53.47 $— $34.83 $4.00 $0.047 6.55 1.37 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 73
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Permanent fixture removal measure (formerly HID permanent removal)
3 or 4 lamp 4 ft T12 and electronic ballast Decommissioning Fixture ENComm_InsLt 8 96% 453.25 $296.74 $— $28.33 $15.00 $0.047 7.85 5.80 1
Permanent fixture removal measure (formerly HID permanent removal)
2 lamp 8-ft T12 and magnetic or electronic ballast
Decommissioning Fixture ENComm_InsLt 8 96% 456.75 $299.03 $— $38.33 $15.00 $0.047 7.87 4.88 1
Permanent fixture removal measure (formerly HID permanent removal)
3 or 4 lamp 8-ft T12 or T12HO/VHO and magnetic or electronic ballast
Decommissioning Fixture ENComm_InsLt 8 96% 1,531.25 $1,002.49 $— $38.89 $25.00 $0.047 9.92 8.73 1
Permanent fixture removal measure (formerly HID permanent removal)
1 lamp 8-ft T12HO and magnetic or electronic ballast
Decommissioning Fixture ENComm_InsLt 8 96% 404.25 $264.66 $— $38.33 $15.00 $0.047 7.47 4.50 1
Permanent
fixture removal measure (formerly HID permanent removal)
1 lamp 8-ft T12VHO
and magnetic or electronic ballast or 2 lamp 8-ft T12HO/VHO and magnetic or electronic ballast
Decommissioning Fixture ENComm_InsLt 8 96% 945.58 $619.06 $— $38.33 $25.00 $0.047 8.56 7.23 1
Permanent fixture removal measure (formerly HID
permanent removal)
4 lamp 2-ft T12 and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 350.00 $229.14 $— $28.33 $15.00 $0.047 6.99 4.97 1
Permanent fixture removal measure (formerly HID permanent removal)
3 or 4 lamp 3-ft T12 and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 463.75 $303.61 $— $26.67 $15.00 $0.047 7.92 6.07 1
Permanent fixture removal measure (formerly HID permanent removal)
3 lamp 4-ft T12 and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 465.50 $304.76 $— $28.33 $15.00 $0.047 7.93 5.89 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 74 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Permanent fixture removal measure (formerly HID permanent removal)
4 lamp 4-ft T12 and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 574.00 $375.79 $— $28.33 $25.00 $0.047 6.94 6.54 1
Permanent fixture removal measure (formerly HID permanent removal)
2 lamp 6-ft T12 and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 416.50 $272.68 $— $32.33 $15.00 $0.047 7.57 5.11 1
Permanent fixture removal measure (formerly HID permanent removal)
1 lamp 6-ft T12HO and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 371.00 $242.89 $— $32.33 $15.00 $0.047 7.19 4.75 1
Permanent fixture removal measure (formerly HID permanent removal)
1 lamp 6-ft T12VHO and magnetic ballast Decommissioning Fixture ENComm_InsLt 8 96% 588.00 $384.96 $— $32.33 $25.00 $0.047 7.02 6.19 1
Permanent
fixture removal measure (formerly HID permanent removal)
2 lamp 6-ft
T12HO/VHO and magnetic ballast
Decommissioning Fixture ENComm_InsLt 8 96% 880.25 $576.29 $— $32.33 $25.00 $0.047 8.34 7.54 1
Permanent fixture removal measure (formerly HID permanent removal)
Mercury vapor using 119 input Watts (W) Decommissioning Fixture ENComm_InsLt 8 96% 416.50 $272.68 $— $41.67 $15.00 $0.047 7.57 4.35 1
Permanent fixture removal measure (formerly HID permanent removal)
Mercury vapor using > 120 input W Decommissioning Fixture ENComm_InsLt 8 96% 1,760.50 $1,152.58 $— $44.17 $25.00 $0.047 10.27 8.77 1
Permanent fixture removal measure (formerly HID permanent removal)
High pressure sodium using 116 input W Decommissioning Fixture ENComm_InsLt 8 96% 406.00 $265.80 $— $41.67 $15.00 $0.047 7.49 4.28 1
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 75
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Permanent fixture removal measure (formerly HID permanent removal)
High pressure sodium using > 120 input W Decommissioning Fixture ENComm_InsLt 8 96% 1,591.80 $1,042.13 $— $43.93 $25.00 $0.047 10.02 8.48 1
Permanent fixture removal measure (formerly HID permanent removal)
Metal halide using 142 input W Decommissioning Fixture ENComm_InsLt 8 96% 497.00 $325.38 $— $41.67 $15.00 $0.047 8.14 4.88 1
Permanent fixture removal measure (formerly HID permanent removal)
Metal halide using > 150 input W Decommissioning Fixture ENComm_InsLt 8 96% 1,790.25 $1,172.05 $— $44.17 $25.00 $0.047 10.31 8.82 1
Permanent fixture removal measure (formerly HID permanent removal)
Incandescent/cfl using 100–200 input W Decommissioning Fixture ENComm_InsLt 8 96% 437.50 $286.43 $— $24.33 $15.00 $0.047 7.73 6.18 1
Permanent
fixture removal measure (formerly HID permanent removal)
Incandescent/cfl using ≥ 200 input W Decommissioning Fixture ENComm_InsLt 8 96% 875.00 $572.85 $— $27.67 $25.00 $0.047 8.32 8.01 1
Compact Fluorescents (CFLs)
Screw-in compact fluorescent ≤ 32 W Fixture using ≥ 60 input w Fixture ENComm_InsLt 6 96% 98.00 $48.62 $— $23.00 $2.00 $0.047 7.07 1.74 1
CFLS Screw-in compact fluorescent 33 to 59 W Fixture using ≥ 100 input W Fixture ENComm_InsLt 6 96% 143.50 $71.20 $— $31.00 $4.00 $0.047 6.36 1.86 1
CFLS
Screw-in compact fluorescent ≥ 60 W Fixture using ≥ 150 input W Fixture ENComm_InsLt 6 96% 175.00 $86.83 $— $29.00 $20.00 $0.047 2.95 2.26 1
CFLS Screw-in cold-cathode ≤ 32 W Fixture using ≥ 60 input W Fixture ENComm_InsLt 6 96% 175.88 $87.26 $— $35.38 $4.00 $0.047 6.83 1.98 1
CFLS
Hard-wired compact fluorescent ≤ 49 W and electronic ballasts
Fixture using ≥ 90 input W Fixture ENComm_InsLt 6 96% 262.78 $130.38 $— $85.00 $30.00 $0.047 2.96 1.32 1
CFLS
Hard-wired compact fluorescent 50–99 W and electronic ballasts
Fixture using ≥ 150 input W Fixture ENComm_InsLt 6 96% 471.10 $233.74 $— $104.50 $40.00 $0.047 3.61 1.81 1
Light Emitting Diodes (LEDs) Screw-in or pin-based led ≤ 10 W Fixture using ≥ 40 input W Fixture ENComm_InsLt 12 96% 105.00 $100.05 $— $45.00 $10.00 $0.047 6.43 1.98 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 76 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Ceramic/pulse start/electronic metal halide
Pulse start metal halides 200–1000 w Screw-in reduced wattage metal halide, > 125 W
Fixture ENComm_InsLt 8 96% 476.85 $312.19 $— $70.83 $25.00 $0.047 6.32 3.28 1
Ceramic/pulse start metal halide
150 to 250 input W metal halide Fixture (lamp & ballast) using ≥ 295 input W
Fixture ENComm_InsLt 12 96% 570.50 $543.58 $— $185.00 $30.00 $0.047 9.19 2.54 1
Ceramic/pulse start metal halide
251 to 360 input W metal halide Fixture (lamp & ballast) using ≥ 450 input W
Fixture ENComm_InsLt 12 96% 499.63 $476.05 $— $217.50 $55.00 $0.047 5.82 1.95 1
Ceramic/pulse start metal halide
361+ input W metal halide Fixture (lamp & ballast) using ≥ 600 input W
Fixture ENComm_InsLt 12 96% 2,033.50 $1,937.55 $— $245.00 $105.00 $0.047 9.27 5.55 1
LED exits
LED exit sign or equivalent (5 W or less)
Exit sign using ≥ 18 W Fixture IPC_8760 16 96% 88.67 $101.07 $— $68.69 $25.00 $0.047 3.33 1.37 1
Lighting
controls
Wall switch occupancy
sensor
Manual or no
prior control
Fixture ENComm_InsLt 10 96% 149.30 $120.31 $— $90.00 $35.00 $0.047 2.75 1.22 1
Lighting controls Wall or ceiling mount occupancy sensor Manual or no prior control Fixture ENComm_InsLt 10 96% 472.17 $380.48 $— $130.00 $50.00 $0.047 5.06 2.45 1
Lighting controls Fixture mount occupancy sensor Manual or no prior control Fixture ENComm_InsLt 10 96% 252.22 $203.24 $— $100.00 $50.00 $0.047 3.15 1.78 1
Lighting controls
Interior photocell control (dimming, step-dimming or switching)
Manual or no prior control Fixture ENComm_InsLt 10 96% 379.42 $305.74 $— $130.00 $40.00 $0.047 5.08 2.03 1
Lighting controls
Auto-off time switch or time clock control (minimum of 100 W connected to load)
Manual or no prior control Fixture ENComm_InsLt 10 96% 272.74 $219.78 $— $125.00 $40.00 $0.047 3.99 1.57 1
Case/walk-in lighting T8 fluorescent lighting T12 fluorescent lighting Lamp ENComm_Refrigeration 6 96% 309.31 $147.27 $— $44.70 $15.00 $0.047 4.79 2.44 2
Case/walk-in lighting LED display case lighting T12 fluorescent lighting Linear Foot ENComm_Refrigeration 8 96% 111.25 $70.01 $— $42.72 $15.00 $0.047 3.32 1.43 3
T8 to LED case lighting LED reach in and open display case lighting T8 fluorescent lighting Linear Foot ENComm_Refrigeration 8 96% 77.75 $48.93 $— $44.38 $10.00 $0.047 3.44 1.01 4
Case/Walk-in Lighting
Fluorescent walk-in light fixture Incandescent
walk-in light fixture
Fixture ENComm_Refrigeration 6 96% 627.99 $299.00 $— $47.49 $25.00 $0.047 5.27 3.77 2
A/C & Heat Pump Units PTAC/PTHP unit, min 12 EER Standard PTAC/PTHP unit Unit ENComm_Cooling 12 80% 562.50 $627.33 $— $255.00 $50.00 $0.047 6.57 2.09 5
A/C & Heat Pump Units 5 ton or less 1 phase A/C unit, min 15 SEER Standard 1–5 ton A/C unit Ton ENComm_Cooling 15 80% 130.29 $175.17 $— $50.00 $25.00 $0.047 4.50 2.74 5
A/C & Heat Pump Units 5 ton or less 1 phase A/C unit, min 16 SEER Standard 5 ton or less A/C unit Ton ENComm_Cooling 15 80% 183.22 $246.34 $— $100.00 $50.00 $0.047 3.36 2.00 5
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 77
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
AC & Heat Pump Units 5 ton or less 1 phase A/C unit, min 17 SEER Standard 5 ton or less A/C unit Ton ENComm_Cooling 15 80% 229.93 $309.13 $— $150.00 $75.00 $0.047 2.88 1.70 5
AC & Heat Pump Units 5 ton or less 3 phase A/C unit, min 14 SEER Standard 1-5 ton A/C unit Ton ENComm_Cooling 15 80% 362.96 $487.98 $— $75.00 $50.00 $0.047 5.82 4.48 5
AC & Heat Pump Units 5 ton or less 3 phase A/C unit, min 15 SEER Standard 5 ton or less A/C unit Ton ENComm_Cooling 15 80% 423.45 $569.31 $— $75.00 $75.00 $0.047 4.80 4.80 5
AC & Heat Pump Units 5 ton or less 3 phase A/C unit, min 16 SEER Standard 5 ton or less A/C unit Ton ENComm_Cooling 15 80% 476.38 $640.47 $— $150.00 $100.00 $0.047 4.19 3.16 5
AC & Heat Pump Units 6–10 ton ac unit, must meet CEE tier 1 Standard 6–10 ton A/C unit Ton ENComm_Cooling 15 80% 130.15 $174.98 $— $100.00 $50.00 $0.047 2.49 1.46 5
AC & Heat Pump Units
11–19 ton ac unit, min 10.8 EER must meet CEE tier 1
Standard 11–19 ton A/C unit Ton ENComm_Cooling 15 80% 197.67 $265.76 $— $100.00 $50.00 $0.047 3.59 2.14 5
AC & Heat Pump Units
20 ton or more A/C unit, min 10 EER must meet CEE tier 1
Standard 20 ton+ A/C unit Ton ENComm_Cooling 15 80% 112.72 $151.55 $— $75.00 $50.00 $0.047 2.19 1.61 5
Economizers Air-side economizer control addition No prior control Ton ENComm_Cooling 15 80% 300.00 $403.34 $— $170.00 $75.00 $0.047 3.62 1.95 2, 6
Economizers Water-side economizer control addition No prior control Ton ENComm_Cooling 10 80% 1,199.10 $1,138.47 $— $463.00 $75.00 $0.047 6.93 2.06 2, 6
Economizers Air-side economizer system repair Non-functional Economizer Unit ENComm_Cooling 15 80% 4,499.29 $6,049.13 $— $630.00 $250.00 $0.047 10.49 6.32 2, 6
Evaporative coolers/pre-coolers
Pre-cooler added to condenser Standard air cooled A/C unit Ton ENComm_Cooling 10 80% 832.30 $790.22 $— $200.00 $100.00 $0.047 4.54 2.89 2
Evaporative coolers/pre-coolers
Retrofit to direct evaporative cooler Replacing standard A/C unit Ton ENComm_Cooling 15 80% 902.52 $1,213.41 $— $400.00 $200.00 $0.047 4.00 2.41 2
Evaporative coolers/pre-coolers
Retrofit to indirect evaporative cooler Replacing standard A/C unit Ton ENComm_Cooling 15 80% 676.89 $910.06 $— $550.00 $300.00 $0.047 2.19 1.37 2
Programmable thermostats 7-day, two-stage setback thermostat Manual thermostat Unit ENComm_HVAC 11 80% 4,209.94 $3,903.54 $— $174.76 $40.00 $0.047 13.13 9.03 2, 6
Automated control systems
Energy management control systems Manual controls Square Feet ENComm_HVAC 14 80% 1.20 $1.38 $— $0.95 $0.30 $0.047 3.09 1.26 2, 6
Automated control systems
Control system reprogramming/optimization
Automated control system Square Feet ENComm_HVAC 4 80% 0.75 $0.26 $— $0.15 $0.10 $0.047 1.57 1.21 5, 6
Automated control systems
Lodging room occupancy control system
Manual controls Room ENComm_HVAC 12 80% 900.00 $901.96 $— $75.00 $50.00 $0.047 7.82 6.43 5, 6
Variable speed fans/pumps Variable speed drive, fan Single speed HVAC system fan HP ENComm_HVAC 15 96% 1,078.29 $1,309.08 $— $187.00 $60.00 $0.047 11.35 5.40 2, 6
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 78 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Variable speed fans/pumps
Variable speed drive, pump Single speed HVAC system pump
HP ENComm_HVAC 15 96% 891.74 $1,082.60 $— $187.00 $60.00 $0.047 10.20 4.64 2, 6
Variable speed controls Variable speed drives Standard motor, 5-200 hp HP ENComm_Misc 10 96% 3,542.00 $2,770.68 $— $187.00 $60.00 $0.047 11.74 7.63 2
Premium windows
SHGC of .30 or less and u-factor .30 or less.
Standard window Square Feet ENComm_HVAC 30 80% 1.38 $2.72 $— $1.50 $1.50 $0.047 1.39 1.39 2
Efficient windows
SHGC of .40 or less and u-factor .42 or less.
Standard window Square Feet ENComm_HVAC 30 80% 0.92 $1.81 $— $0.68 $1.00 $0.047 1.39 1.84 2
Window shading Adding window shade screen No screen or other shading Square Feet ENComm_Cooling 10 80% 2.10 $1.99 $— $1.00 $0.50 $0.047 2.66 1.60 2
Reflective roofing Adding reflective roof treatment Non-reflective low pitch roof Square Feet ENComm_Cooling 15 80% 0.40 $0.54 $— $0.32 $0.05 $0.047 6.25 1.51 2
Roof/ceiling insulation Increasing to R24 min insulation Insulation level, R11 or less Square Feet ENComm_HVAC 40 80% 0.92 $2.09 $— $0.83 $0.10 $0.047 11.69 2.30 2
Roof/ceiling insulation Increasing to R38 min insulation Insulation level, R11 or less Square Feet ENComm_HVAC 40 80% 1.46 $3.32 $— $0.95 $0.20 $0.047 9.88 3.04 2
Wall insulation Increase to R11 min insulation Insulation level, R5 or less Square Feet ENComm_HVAC 40 80% 1.04 $2.38 $— $0.62 $0.05 $0.047 19.18 3.45 2
Wall insulation Increase to R19 min insulation Insulation level, R5 or less Square Feet ENComm_HVAC 40 80% 2.44 $5.54 $— $0.74 $0.10 $0.047 20.67 6.09 2
Refrigeration cases
Efficient, medium-temp open case Standard
medium-temp open case
Linear Foot ENComm_Refrigeration 16 96% 148.18 $174.67 $— $100.00 $20.00 $0.047 6.22 1.62 2
Refrigeration cases
Efficient, medium-temp reach-in Standard medium-temp open case
Linear Foot ENComm_Refrigeration 16 96% 564.94 $665.92 $— $100.00 $100.00 $0.047 5.05 5.05 2
Refrigeration cases Efficient, low-temp reach-in (reach-in) Standard low-temp reach-in Linear Foot ENComm_Refrigeration 16 96% 478.36 $563.87 $— $100.00 $150.00 $0.047 3.14 4.35 2
Refrigeration cases Efficient, low-temp reach-in (open case) Standard low-temp open case Linear Foot ENComm_Refrigeration 16 96% 1,208.00 $1,423.94 $— $100.00 $150.00 $0.047 6.61 8.61 2
Refrigeration cases Efficient, low-temp reach-in (coffin case) Standard low-temp coffin case Linear Foot ENComm_Refrigeration 16 96% 703.42 $829.16 $— $100.00 $55.00 $0.047 9.04 6.06 2
Refrigeration cases Vertical night covers No covers present Linear Foot ENComm_Refrigeration 5 96% 148.00 $58.87 $— $9.00 $9.00 $0.047 3.54 3.54 2
Refrigeration cases Horizontal night covers No covers present Linear Foot ENComm_Refrigeration 5 96% 59.00 $23.47 $— $9.00 $5.00 $0.047 2.90 1.94 2
Refrigeration cases Refrigeration line insulation No insulation present Linear Foot ENComm_Refrigeration 11 96% 17.00 $14.41 $— $2.00 $1.00 $0.047 7.69 5.01 2
Refrigeration cases Door gasket—walk-in No or damaged door gasket Linear Foot ENComm_Refrigeration 4 96% 137.50 $43.70 $— $4.00 $2.00 $0.047 4.96 4.04 2
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 79
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Refrigeration cases Door gasket—reach-in Damaged door gasket Linear Foot ENComm_Refrigeration 4 96% 92.50 $29.40 $— $4.00 $1.00 $0.047 5.28 3.43 2
Refrigeration cases
Auto-closer—walk-in No or damaged auto closer, low-temp
Unit ENComm_Refrigeration 8 96% 2,470.00 $1,554.33 $— $433.00 $50.00 $0.047 8.98 2.80 2
Refrigeration cases Auto-closer—reach-in Damaged auto closer, low-temp Unit ENComm_Refrigeration 8 96% 1,297.00 $816.18 $— $300.00 $50.00 $0.047 7.06 2.23 2
Refrigeration cases
Auto-closer—walk-in No or damaged auto closer, med-temp
Unit ENComm_Refrigeration 8 96% 1,067.00 $671.45 $— $433.00 $40.00 $0.047 7.15 1.38 2
Refrigeration cases Auto-closer—reach-in Damaged auto closer, med-temp Unit ENComm_Refrigeration 8 96% 243.00 $152.92 $— $125.00 $40.00 $0.047 2.85 1.10 2
Refrigeration cases No-heat glass doors Standard low-temp reach-in Unit ENComm_Refrigeration 12 96% 749.00 $687.45 $— $200.00 $50.00 $0.047 7.75 2.88 2
Refrigeration cases
Anti-sweat heat (ASH) controls Low or med-temp case w/out controls
Linear Foot ENComm_Refrigeration 8 96% 299.50 $188.47 $— $48.75 $40.00 $0.047 3.35 2.90 7
Vending machines ENERGY STAR vending machine Standard vending machine Unit ENComm_Misc 14 96% 1,472.00 $1,563.31 $— $350.00 $75.00 $0.047 10.41 3.68 2
Vending machines Beverage machine control Vending machine with no sensor Unit ENComm_Misc 14 96% 546.50 $580.40 $— $170.00 $75.00 $0.047 5.53 2.90 2
Vending machines Other cold product control Vending machine with no sensor Unit ENComm_Misc 14 96% 546.50 $580.40 $— $170.00 $50.00 $0.047 7.36 2.92 2
Vending machines Non-cooled snack control Vending machine with no sensor Unit ENComm_Misc 14 96% 382.55 $406.28 $— $170.00 $25.00 $0.047 9.07 2.14 2
Commercial kitchen equipment
ENERGY STAR dishwasher Standard dishwasher Unit ENComm_Misc 11 96% 231.00 $197.54 $— $55.00 $15.00 $0.047 7.33 2.95 2
Commercial kitchen equipment
Low-temperature dish machine Dish machine w/electric booster kW ENComm_Misc 13 96% 657.86 $654.56 $— $127.00 $75.00 $0.047 5.93 4.03 2
Commercial kitchen equipment
ENERGY STAR refrigerator Standard refrigerator Refrigerator ENComm_Misc 13 96% 85.71 $85.28 $— $30.00 $30.00 $0.047 2.41 2.41 2
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 ft3.
Refrigerator ENComm_Refrigeration 12 96% 4.25 $3.90 $— $73.62 $75.00 $0.047 0.05 0.05 8, 9
Commercial kitchen equipment
Ice maker, up to 200 lbs/day Standard ice maker of the same size
Unit ENComm_Misc 10 96% 161.20 $126.10 $— $- $100.00 $0.047 1.13 1.13 10
Commercial kitchen equipment
Ice maker, more than 200 lbs/day Standard ice maker of the same size
Unit ENComm_Misc 10 96% 596.33 $466.47 $— $- $200.00 $0.047 1.96 1.96 11
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 80 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Evaporator fans Evaporator fan controls Med-temp walk-in with no controls Unit ENComm_Refrigeration 5 96% 361.00 $143.59 $— $85.00 $25.00 $0.047 3.28 1.38 2
Evaporator fans Efficient evaporator fan motors Med- or low-temp walk-in Motor ENComm_Refrigeration 10 96% 478.30 $370.92 $— $161.00 $100.00 $0.047 2.91 1.97 2
Evaporator fans ECM case fan motors Standard,
shaded-pole fan motors
Motor ENComm_Refrigeration 15 96% 477.00 $532.59 $— $96.63 $60.00 $0.047 6.20 4.35 12
Compressors/condensers Efficient, low-temp compressor Standard low-temp compressor Ton ENComm_Refrigeration 15 96% 1,051.00 $1,173.49 $— $132.00 $45.00 $0.047 11.93 6.33 2
Compressors/condensers Efficient, air-cooled condenser Standard air cooled condenser Ton ENComm_Refrigeration 15 96% 410.01 $457.80 $— $140.30 $100.00 $0.047 3.68 2.78 2
Compressors/condensers Efficient, water-cooled condenser Standard air cooled condenser Ton ENComm_Refrigeration 15 96% 559.03 $624.18 $— $209.00 $100.00 $0.047 4.75 2.59 2
Compressors/condensers Efficient, evaporative, condenser Standard air cooled condenser Ton ENComm_Refrigeration 15 96% 678.74 $757.84 $— $278.00 $200.00 $0.047 3.14 2.37 2
Head/suction
pressure
Floating head pressure
controller
Standard head
pressure control
HP ENComm_Refrigeration 15 96% 692.50 $773.21 $— $271.20 $60.00 $0.047 8.02 2.51 13
Head/suction pressure Floating suction pressure Standard suction pressure control HP ENComm_Refrigeration 16 96% 272.91 $321.69 $— $52.48 $10.00 $0.047 13.53 4.86 2
Office equipment PC network power management No central control Unit ENComm_Office 4 96% 99.00 $31.21 $— $13.80 $10.00 $0.047 2.05 1.64 14
Laundry machines High-efficiency washer Standard washer, electric hot water Washer ENComm_Misc 14 96% 287.00 $304.80 $— $195.00 $25.00 $0.047 7.60 1.45 2
Laundry machines High-efficiency, coin-op washer Coin-op washer, electric hot water Washer ENComm_Misc 8 96% 828.00 $525.63 $— $230.07 $200.00 $0.047 2.11 1.88 2
a Average measure life.
b Net-to-Gross (NTG) percentage. Idaho Power Demand-Side Management Potential Study by Nexant, Inc., 2009.
c Estimated kWh savings measured at the customers meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Evergreen Consulting Group, LLC. Idaho Power Lighting Tool. 2013.
2 Idaho Power Demand-Side Management Potential Study by Nexant, Inc. IPC DSM Potential - Commercial Model 081209.xlsm. 2009.
3 RTF. ComGroceryDisplayCaseLEDs_v2_2 and ComGroceryCaseLEDs_v1.1.xls. 2013. T12 to LED. Averaged the measures for less than 4 W/ln. ft. and 4-8.5 W/ln. ft.
4 RTF. ComGroceryDisplayCaseLEDs_v2_2 and ComGroceryCaseLEDs_v1.1.xls. 2013. T8 to LED. Averaged the measures for less than 4 W/ln. ft. and 4-8.5 W/ln. ft.
5 Savings and participant costs calculated from Idaho Power engineering estimates and research. Participant costs include total install cost of the measure.
6 Saving values identified by ADM Associates as needing further review in impact evaluation. Will be reviewed and updated in 2014.
7 RTF. ComGroceryAntiSweatHeaters_v2_0.xlsm. 2013.
8 RTF. ComRefrigerator_v3.xlsm. Average solid and glass door. 2012.
9 Measure not cost-effective. Will be removed in 2014.
10 RTF. ComIceMaker_v1_1.xlsx. Average of all ENERGY STAR air-cooled models producing less than 200 lbs/day. Measure deactivated by RTF in 2013. Will review for 2014.
11 RTF. ComIceMaker_v1_1.xlsx. Average of all Energy Star ® air cooled models producing between 200-1000 lbs/day. Measure deactivated by RTF in 2013. Will review for 2014.
12 RTF. ComGroceryDisplayECMs_v2_2.xlsm. 2012.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 81
13 RTF. ComGroceryFHPCSingleCompressor_v1_1.xls. 2012. Averaged the measures for condensing unit and remote condenser low and medium temperature.
14 RTF. NonResNetCompPwrMgt_v3_0.xlsm. 2011. RTF reviewed for 2013 and made savings applicable for schools only. Company will review in 2014.
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 82 Demand-Side Management 2013 Annual Report
This page left blank intentionally.
Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 83
Irrigation Efficiency Rewards
Segment: Irrigation
2013 Program Results
Cost Inputs (NPV) Ref Summary of Cost-Effectiveness Results
Program Administration ........................................................................ $ 464,746 Test Benefit Cost Ratio
Menu $ 965,139 Utility Cost Test .................. $ 15,492,895 $ 2,441,386 6.35
Program Incentives ............................................................................... Custom 1,011,501 1,976,640 I Total Resource Cost Test ... 21,412,767 12,462,677 1.72
Total Utility Cost ................................................................................. $ 2,441,386 P Ratepayer Impact Measure Test .........................
15,492,895 9,486,348 1.63
Participant Cost Test .......... 17,339,299 14,759,181 1.17
Measure Equipment and Installation Menu $ 2,702,680
(Incremental Participant Cost) .............................................................. Custom 12,056,502
14,759,181 M
Net Benefit Inputs (NPV) Ref Assumptions for Levelized Calculations
Resource Savings Discount Rate
2013 Annual Gross Energy (kWh)—Menu .................................................... 14,302,824 Nominal (WACC) ................................................................... 7.00%
NPV Cumulative Energy (kWh) ..................................................................... 104,701,908 $ 12,692,056 Real ((1 + WACC) / (1 + Escalation)) – 1 ............................... 3.88%
2013 Annual Gross Energy (kWh)—Custom ................................................. 4,208,397 Escalation Rate ......................................................................... 3.00%
NPV Cumulative Energy (kWh) ..................................................................... 30,807,007 3,734,452 Net-to-Gross—Custom Option Only & NEB ............................... 75.00%
Total Electric Savings .................................................................................... $ 16,426,508 S Average Customer Segment Rate/kWh ..................................... $0.059
Line Losses ............................................................................... 10.90%
Participant Bill Savings
NPV Cumulative Participant Savings ............................................................ Menu $ 5,771,358
Custom 1,698,138
$ 7,469,496 B
Other Benefits
Non-Energy Benefits ..................................................................................... Menu $ 3,151,599
Custom 4,741,563
Total Non-Energy Benefits $ 7,893,163 NEB

Benefits and Costs Included in Each Test
Utility Cost Test ................................ = Menu S + (Custom S * NTG) = P
Total Resource Cost Test ................. = Menu S + (Custom S * NTG) + (NEB * NTG) = P + (Menu M - I) +((Custom M - I) * NTG)
Ratepayer Impact Measure Test ....... = Menu S +(Custom S * NTG) = P + Menu B + (Custom B * NTG)
Participant Cost Test ........................ = B + I + NEB = M

Supplement 1: Cost-Effectiveness Idaho Power Company
Page 84 Demand-Side Management 2013 Annual Report
Notes: Energy savings are combined for projects under the Custom and Menu program. Savings under each Custom project is unique and individually calculated and assessed.
Green Rewind initiative is available to agricultural, commercial, and industrial customers. Agricultural motor rewinds are paid under Irrigation Efficiency.
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.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 85
Year:2013 Program: Irrigation Efficiency Rewards Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Namea Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)b NTGc
Annual Gross Energy Savings (kWh/yr)d
NPV Avoided Costse
Non-Energy Benefit (NEB)
Gross Incremental Participant Costf Incentive/ Unit Admin Cost ($/kWh)g UC Ratioh TRC Ratioi Source
Nozzle Replacement New flow-control-type nozzles replacing existing brass nozzles or worn out flow control nozzles of same flow rate or less.
Brass nozzles or worn out flow control nozzles of same flow rate or less
Unit IPC_Irrigation 4 100% 40.56 $17.48 $— $6.52 $1.50 $0.025 6.93 2.32 1
Nozzle Replacement New nozzles replacing
existing worn nozzles of same flow rate or less
Worn nozzle of
same flow rate or less
Unit IPC_Irrigation 4 100% 40.56 $17.48 $— $2.44 $0.25 $0.025 13.74 5.05 1
Sprinklers Rebuilt or new brass impact sprinklers Unit IPC_Irrigation 5 100% 28.22 $15.12 $— $14.18 $2.75 $0.025 4.37 1.02 1
Levelers Rebuilt wheel line levelers Unit IPC_Irrigation 5 100% 41.68 $22.34 $— $0.93 $0.75 $0.025 12.41 11.28 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 IPC_Irrigation 5 100% 28.00 $15.01 $— $13.66 $2.75 $0.025 4.34 1.04 3
Regulator Replacement New low pressure regulators Unit IPC_Irrigation 5 100% 38.00 $20.36 $— $7.05 $5.00 $0.025 3.41 2.54 3
Gasket Replacement New gaskets for hand lines, wheel lines or portable mainline
Unit IPC_Irrigation 5 100% 169.68 $90.93 $— $4.54 $1.00 $0.025 17.24 10.32 1
Hub Replacement New wheel line hubs Unit IPC_Irrigation 10 100% 72.90 $74.04 $— $57.52 $12.00 $0.025 5.35 1.25 1
New Goose Necks New goose neck with drop tube or boomback Outlet IPC_Irrigation 15 100% 14.50 $20.69 $— $4.80 $1.00 $0.025 15.16 4.01 1
Pipe Repair Cut and pipe press or weld repair of leaking hand lines, wheel lines, and portable mainline
Joint IPC_Irrigation 8 100% 84.31 $70.22 $— $20.71 $8.00 $0.025 6.94 3.08 1
Gasket Replacement New center pivot base boot gasket Unit IPC_Irrigation 8 100% 1,453.84 $1,210.89 $— $287.59 $125.00 $0.025 7.49 3.73 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 No NTG percentage. Deemed savings from RTF includes realization rate.
d Estimated kWh savings 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 Integrated Resource Plan (IRP). f Incremental participant cost prior to customer incentives.
g Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
h Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 86 Demand-Side Management 2013 Annual Report
i Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 RTF. AgIrrigationHardware_v3.xlsm. 2013. Three year weighted average customer participation. Applied percentages to RTF measures in Western Idaho (13%), Eastern Washington & Oregon (4%), and Eastern & Southern Idaho (83%).
2 Average costs from customer applications.
3 RTF. IrrgAgSprinklerNozzleFY10v2_1.xls. Western Idaho. 2010.

Idaho Power Company Supplement 1: Cost-Effectiveness
Demand-Side Management 2013 Annual Report Page 87
Year:2013 Program: Irrigation Efficiency Rewards—Green Motors Market Segment: Irrigation Program Type: Energy Efficiency

Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 15HP
Standard rewind practice
Motor IPC_Irrigation 18 75% 317.00 $519.87 $— $154.35 $30.00 $0.050 9.07 2.86 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 20HP
Standard rewind practice
Motor IPC_Irrigation 18 75% 425.00 $696.98 $— $172.21 $40.00 $0.050 9.10 3.34 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 25HP
Standard rewind practice
Motor IPC_Irrigation 17 75% 595.00 $935.11 $— $196.76 $50.00 $0.050 9.38 3.79 1
Green Motors
Program Rewind
Green Motors
Program Rewind: Motor size 30HP
Standard
rewind practice
Motor IPC_Irrigation 17 75% 640.00 $1,005.84 $— $216.10 $60.00 $0.050 8.75 3.71 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 40HP
Standard rewind practice
Motor IPC_Irrigation 17 75% 746.00 $1,172.43 $— $264.09 $80.00 $0.050 8.00 3.55 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 50HP
Standard rewind practice
Motor IPC_Irrigation 17 75% 802.00 $1,260.44 $— $292.35 $100.00 $0.050 7.20 3.43 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 60HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 765.00 $1,351.84 $— $344.79 $120.00 $0.050 6.83 3.20 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 70HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 788.00 $1,392.48 $— $372.69 $150.00 $0.050 5.88 3.03 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 100HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 1,040.00 $1,837.79 $— $462.33 $200.00 $0.050 5.83 3.18 1
Green Motors Program
Rewind
Green Motors Program Rewind:
Motor size 125HP
Standard rewind
practice
Motor IPC_Irrigation 20 75% 1,157.00 $2,044.54 $— $519.23 $250.00 $0.050 5.31 3.13 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 150HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 1,376.00 $2,431.54 $— $578.37 $300.00 $0.050 5.27 3.29 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 200HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 1,821.00 $3,217.90 $— $696.28 $400.00 $0.050 5.24 3.54 1
Green Motors
Program Rewind
Green Motors
Program Rewind: Motor size 250HP
Standard
rewind practice
Motor IPC_Irrigation 20 75% 2,823.00 $4,988.54 $— $894.90 $500.00 $0.050 6.22 4.17 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 300HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 3,370.00 $5,955.15 $— $904.58 $600.00 $0.050 6.20 4.71 1
Supplement 1: Cost-Effectiveness Idaho Power Company
Page 88 Demand-Side Management 2013 Annual Report
Benefit Cost Benefit/Cost Tests
Measure Name Measure Descriptions Replacing Measure Unit End Use
Measure Life (yrs)a NTGb
Annual Gross Energy Savings (kWh/yr)c
NPV Avoided Costsd
Non-Energy Benefit (NEB)
Gross Incremental Participant Coste Incentive/ Unit Admin Cost ($/kWh)f UC Ratiog TRC Ratioh Source
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 350HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 3,929.00 $6,942.96 $— $948.10 $700.00 $0.050 6.20 5.07 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 400HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 4,456.00 $7,874.23 $— $1,058.93 $800.00 $0.050 6.16 5.12 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 450HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 5,003.00 $8,840.83 $— $1,157.49 $900.00 $0.050 6.15 5.22 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 500HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 5,567.00 $9,837.48 $— $1,250.49 $1,000.00 $0.050 6.16 5.32 1
Green Motors Program Rewind
Green Motors Program Rewind: Motor size 600HP
Standard rewind practice
Motor IPC_Irrigation 20 75% 6,193.00 $10,943.69 $— $1,842.75 $1,200.00 $0.050 5.80 4.33 1
a Average measure life.
b Net-to-Gross (NTG) percentage.
c Estimated kWh savings measured at the customer’s meter, excluding line losses.
d Sum of NPV of avoided costs. Based on end-use load shape; measure life; and savings, including line losses and alternative costs by pricing period as provided in the 2011 Integrated Resource Plan (IRP).
e Incremental participant cost prior to customer incentives.
f Average program administration and overhead costs to achieve each kWh of savings. Calculated from 2013 actuals.
g Utility Cost Ratio = (NPV Avoided Costs * NTG)/((Admin Cost/kWh * kWh Savings ) + Incentives).
h Total Resource Cost Ratio = ((NPV Avoided Costs + NEB) * NTG) / ((Admin Cost/kWh * kWh Savings) + Incentives + ((Incremental Participant Cost - Incentives) * NTG))
1 Regional Technical Forum (RTF). AgGreenMotorRewind_v2_0.xlsm. 2013.