20120430DSM 2011 Report.pdf

Rocky Mountain Power
2011 Energy Efficiency
and Peak Reduction
Annual Report – Idaho

Submitted April 30, 2012
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Table of Contents

Introduction and Executive Summary ............................................................................................ 4 
2011 Performance and Activity ...................................................................................................... 6 
Company Filings with the Idaho Public Utilities Commission .................................................... 10 
Outreach and Communications ..................................................................................................... 12 
Peak Reduction Program and Activity .......................................................................................... 14 
Energy Efficiency Programs and Activity .................................................................................... 17 
Residential Energy Efficiency Programs and Activity ................................................................. 19 
Non-Residential Energy Efficiency Programs and Activity ......................................................... 28 
Summary of 2011 Results ............................................................................................................. 34 
Balancing Account Summary ....................................................................................................... 36 
Cost Effectiveness ......................................................................................................................... 37 
Appendices:................................................................................................................................... 39 

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Table of Tables

Table 1: Total Portfolio Performance ............................................................................................ 4 
Table 2: Energy Efficiency and Peak Reduction Annual Results .................................................. 6 
Table 3: Program Evaluation Timeline .......................................................................................... 9 
Table 4: Load Management Portfolio Performance ..................................................................... 14 
Table 5: Irrigation Load Control Program Performance .............................................................. 15 
Table 6: Energy Efficiency Portfolio Performance ..................................................................... 17 
Table 7: Commercial & Industrial Energy Efficiency Portfolio .................................................. 18 
Table 8: Residential Energy Efficiency Portfolio ........................................................................ 18 
Table 9: Home Energy Savings Program Performance ............................................................... 19 
Table 10: Home Energy Savings Measure Performance ............................................................. 20 
Table 11: See ya later, refrigerator® Program Performance ....................................................... 22 
Table 12: See ya later, refrigerator® Results ............................................................................... 22 
Table 13: Low Income Weatherization Performance .................................................................. 25 
Table 14: Conservation Education ............................................................................................... 27 
Table 15: Energy FinAnswer Program ........................................................................................ 28 
Table 16: Energy FinAnswer by Measure Type .......................................................................... 28 
Table 17: FinAnswer Express Program ....................................................................................... 30 
Table 18: FinAnswer Express by Measure Type ......................................................................... 30 
Table 19: Agricultural Energy Services Program ........................................................................ 32 
Table 20: Agricultural Energy Savers by Measure ...................................................................... 33 
Table 21: Revenues (Schedule 191) by Customer Type .............................................................. 34 
Table 22: Expenditures (Schedule 191) by Customer Type ........................................................ 34 
Table 23: Energy Efficiency kWh Saved by Customer Type ...................................................... 35 
Table 24: Balancing Account Activity (Schedule 191) ............................................................... 36 

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Introduction and Executive Summary

Rocky Mountain Power (the “Company”) working in partnership with its retail customers and
with the approval of the Idaho Public Utilities Commission (the “IPUC”), acquires energy
efficiency and peak reduction resources as cost-effective alternatives to the acquisition of supply-
side resources. These resources assist the Company in efficiently addressing load growth and
contribute to the Company’s ability to meet system peak requirements. Company energy
efficiency and peak reduction programs provide participating Idaho customers with tools that
enable them to reduce or assist in the management of their energy usage, while reducing the
overall costs to Rocky Mountain Power’s customers. These resources are a valuable component
of Rocky Mountain Power’s resource portfolio and are relied upon in resource planning as a least
cost alternative to supply–side resources.

Rocky Mountain Power currently offers seven energy efficiency and peak reduction programs in
Idaho. In 2011, costs associated with these programs were recovered through the Customer
Efficiency Services Rate Adjustment (Schedule 191), with the exception of the expenses
associated with the irrigation load control program1. The results of Rocky Mountain Power’s
Idaho energy efficiency and peak reduction programs for the reporting period of January 1, 2011
through December 31, 2011 are summarized in Table 1 below.

Table 1: Total Portfolio Performance2
System Benefit Revenues Collected 5,356,975$
System Benefit Expenditures (excludes Irrigation) 2,574,217$
Total Expenditures including Irrigation 11,898,261$
MW of Participaton Load (Gross at Generation) 281.4
kWh/Yr Savings (Gross at Generation) 9,660,007
kWh/Yr Savings (at Site) 8,821,524
PTRC TRC UCT RIM PCT
Portfolio Cost Effectiveness 4.354 3.958 2.228 1.733 4.870
Levelized Cost ($/kWh) NA NA NA
Lifecycle Revenue Impact ($/kWh)
(Note: See notes for Table 2 for explanation of Gross Savings and line loss assumptions)

Overall first year energy savings for 2011 achieved through energy efficiency programs,
decreased approximately 26 percent while Customer Efficiency Services expenditures decreased
27 percent.

1 The Idaho Public Utilities Commission, in Case No. PAC-E-10-07, ordered that the costs associated with the Idaho
Irrigation Load Control Program should be allocated as system costs and not situs to Idaho. 2 Savings and expenditures from school projects completed under the Idaho Office of Energy Resources Energy
Efficiency Incentives Agreement were removed from the PTRC, TRC and PCT cost effectiveness calculations and
results. See Appendix 1.
5
At the end of 2011, the Customer Efficiency Services balancing account had an unfunded
balance of $1,564,182.

Rocky Mountain Power’s energy efficiency and peak reduction portfolio level performance for
2011 was cost effective across all five cost effectiveness tests.

6
2011 Performance and Activity

Program and Sector level results for 2011 are provided on the following table3. Program
Schedules are noted in parenthesis in the table.

Table 2: Energy Efficiency and Peak Reduction Annual Results
Program Units
kWh/Yr Savings
(at site)
kWh/Yr Savings
(at generator)
Program
Expenditures
Low Income Weatherization (21)100 228,605 251,363 253,809$
Low Income Education Program (21)168 22,848 25,123 42,500$
Refrigerator Recycling (117)710 943,176 1,037,069 107,033$
Home Energy Savings (118)7,978 2,544,602 2,797,917 613,890$
Total Residential 8,956 3,739,231 4,111,472 1,017,233$
Energy FinAnswer (125)1 9,727 10,634 18,303$
FinAnswer Express (115)70 2,219,662 2,426,668 632,813$
Total Commercial 71 2,229,389 2,437,302 651,116$
Energy FinAnswer (125)13 478,200 521,501 136,064$
FinAnswer Express (115)2 14,311 15,607 67,910$
Agricultural Energy Services (155)7,978 2,360,393 2,574,126 490,980$
Total Industrial 7,993 2,852,904 3,111,234 694,954$
Total Energy Efficiency 8,821,524 9,660,008 2,363,302
Energy Efficiency Evaluation Costs 210,915$
Total System benefit Expenditures - All Programs 2,574,217$
Irrigation Load Control Expenditures (Schedule 72 and 72A) 9,324,044$
Total Idaho Program Expenditures 11,898,261$

3 Savings values in this table are shown prior to any net-to-gross adjustment. The values at generation include line
losses between the customer site and the generation source. The Company’s line losses by sector are 9.96 percent for
residential, 9.33 percent for commercial and 9.06 percent for industrial. These values are based on the Company’s
2007 Transmission and Distribution Loss Study by Management Applications Consulting published in October
2008.
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Major Trends and Activities

In 2011, the Company’s energy efficiency program performance decreased across all customer
sectors on a kWh/year basis compared to 2010 results. Residential savings decreased by 16
percent, commercial by 35 percent, and industrial by 30 percent (including agricultural sector),
respectively.

Expenditures related to energy efficiency program delivery decreased in 2011 as compared to
2010 by 27 percent. At a sector level, the residential sector expenditures decreased by 37 percent
and commercial and industrial sectors decreased by 17 percent.

Results of the irrigation load control program reflect program changes agreed to in a stipulation
between the Company, Idaho Irrigation Pumper Association and the Idaho Public Utilities
Commission Staff, approved by Commission Order 32235 on April 27, 2011. The order froze
program participation to existing participants and the participants were required to either reduce
participating loads by 18 percent or accept an 18 percent reduction in the incentive value. Of the
283 megawatts of connected load in 2010, 258 megawatts participated during the 2011 control
season (as measured at the customer meter).

Cost Effectiveness

Consistent with the requirements outlined in the Memorandum of Understanding signed by the
Company and Idaho Commission Staff, the Company provides cost effectiveness results utilizing
five cost effectiveness tests:

1. PacifiCorp Total Resource Cost Test (PTRC)
2. Total Resource Cost Test (TRC)
3. Utility Cost Test (UCT)
4. Ratepayer Impact Test (RIM)
5. Participant Cost Test (PCT)

The PTRC (also referred to as the TRC + Conservation Adder) is a variation of the TRC test. It
includes a 10 percent benefit adder to account for non-quantified benefits of conservation
resources over supply-side alternatives. This is consistent with Northwest Power Planning and
Conservation Act.

The TRC compares the total cost of a supply side resource to the total cost of an energy
efficiency program resource, including costs paid by the customer in excess of the program
incentives provided. This test is used to determine if an energy efficiency program is cost
effective from a total cost perspective.

The UCT, also referred to as the Program Administrator Test, compares the portion of the
resource costs paid directly by the Company. This test is useful in determining the cost
effectiveness of the resource from the Company’s perspective; however it does not account for
the portion of the cost that is borne directly by customers.

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The RIM test determines the impact an energy efficiency program has on rates. The ultimate
objective of an energy efficiency program is to encourage customers to use less energy, thereby
reducing energy sales. The RIM test accounts for the cost of lost revenues to the utility
associated with kWh sales reductions. The net impact of these reductions can put near-term
upward pressure on rates even when total costs are lower with a successful energy efficiency
program than with a supply-side alternative. One challenge with the RIM test however is that its
more sensitive than the other tests to differences between long-term projections of marginal costs
and long-term projections of rates, two cost streams that are difficult to quantify with certainty.

The PCT test compares the portion of the resource cost paid directly by participants to the
savings realized by the participant. For the PCT test, bill savings are the realized benefit of
energy efficiency rather than the avoided supply-side costs.

The results for each test are provided at several levels:
1. Overall portfolio level, consolidation of all Company delivered programs
2. Load control and energy efficiency program portfolios separately
3. Residential and non-residential energy efficiency program portfolios separately
4. At the individual program level

Results of the cost effectiveness tests are included in the summary overview for each program.
Further details including key inputs and assumptions for each of the cost effectiveness tests are
provided in the cost effectiveness section of this report.

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Program Evaluation

Rocky Mountain Power’s Program Evaluation Timeline (Table 3 below) provides a summary of
the scheduled completion of program evaluations.

Table 3: Program Evaluation Timeline
Program
Evaluation
Type Status
Anticipated
Year
Complete
Program
Year(s)
Evaluated Evaluator
Low Income Weatherization Process and
Impact Complete 2011 2007-2009 Cadmus
Home Energy Savings Process and
Impact In Process Q1 2012 2009-2010 Cadmus
See ya later, refrigerator® Process and
Impact In Process Q1 2012 2009-2010 Cadmus
Energy FinAnswer Process and
Impact In Process 2012 2009-2011 Navigant
FinAnswer Express Process and
Impact In Process 2012 2009-2011 Navigant
Irrigation Energy Savers Process and
Impact In Process 2012 2009-2011 Navigant
As noted in Table 3, the Company completed a third-party independent process and impact
evaluation for low income weatherization for program years 2007 – 2009. Findings from these
evaluations will be key inputs to ongoing program design considerations as well as inputs to
future cost effectiveness determinations.

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Company Filings with the Idaho Public Utilities Commission

The Company made several filings with the Commission regarding its energy efficiency and
peak reduction programs during 2011. Summary information concerning these filings is provided
as follows:

On January 20, 2011, Rocky Mountain Power filed an application with the Commission
requesting prospective changes to the Dispatchable Irrigation Load Control program, which is
administered through Schedule 72A. This matter was subsequently assigned to Case No. PAC-E-
11-06. Through the application, the Company proposed adding language to the tariff to control
participation, in an effort to address adverse impacts to the distribution system. The Company
also proposed changing the opt-out or liquidated damages penalty from a variable market price
for energy structure to a penalty that results in a decrease in participation credits or participant
incentive for each opt-out over 1 per season. Other proposed changes were minor administrative
adjustments to tariff language. Ultimately a stipulation was entered into by the Company, Idaho
Irrigation Pumper Association and the Idaho Public Utilities Commission Staff to set the
operating parameters for the 2011 – 2012 control seasons. The stipulation provided for the
following changes in the operation of the program:

• For 2011 and 2012, the parties agreed that program participation would be targeted to
achieve 232 megawatts of participation load. The company would work to reduce
program participation from the 2010 level of 283 megawatts by 18 percent to
approximately 232 megawatts. The Company would work with participants to identify
the approximate reduction necessary to achieve an 18 percent reduction. Participants
without the ability to identify an 18 percent reduction by segmenting pumps would
receive a payment equal to 82 percent of their available participation credit incentive.
• Incentive payments for 2011 were reduced by $1.45 per kilowatt per year to reflect
system constraints.
• The Company committed to invest a minimum of $1.3 million in capital improvements to
identify and install equipment needed to reduce the constraints on the distribution system
prior to the start of the 2012 control season.
• As part of the annual irrigation report, the Company agreed to complete a review of
circuit loading and recommend any needed changes or investments for the following
years’ irrigation season to continue to address circuit load issues.
• The dispatch program season was changed to June 1 – August 31 of each year.
• During 2011 – 2012 program seasons no new Program participants or additional existing
participants load will be accepted into the program.
• At the discretion of the Company and by agreement with selected customers, the
Company could require the manual operation of selected pumps during control events.
• Opt-out provisions were modified to reflect the loss of participation credits rather than
market prices.

On February 28, 2011, the Company submitted its 2010 Energy Efficiency and Peak Reduction
Balancing Account Review with the Commission.

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On April 27, 2011, the Commission issued an order approving the changes incorporated by the
parties in the stipulation.

On April 29, 2011, the Company submitted its 2010 Idaho Energy Efficiency and Peak
Reduction Annual Report with the Commission.

On April 29, 2011, Rocky Mountain Power filed an application with the Commission seeking
authorization to suspend future program evaluations for Schedule 21, Low Income
Weatherization Services Optional for Income Qualifying Customers. This matter was
subsequently assigned to Case No. PAC-E-11-13. On January 18, 2012, the Commission issued
an order denying the Company’s request.
.

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Outreach and Communications

The following outreach, communications and promotional activities occurred to support Rocky
Mountain Power’s energy efficiency programs in 2011.

Home Energy Savings program
Two bill inserts for the Home Energy Savings program featuring ENERGY STAR® ceiling fans
and high efficiency heat pumps.
New point-of-purchase materials were developed in 2011. These items included in-store banners
for big box retailers, compact fluorescent lighting (“CFL”) cardboard kiosks, CFL booklet, CFL
shelf flap, appliance table tents, appliance/lighting danglers and room air conditioner box
stickers.

A “blue envelope” promotion ran from September 19 to November 15 encouraging the purchase
of qualifying dishwashers, clothes washers and refrigerators. A total of 135 applications were
received as a result of this effort.

In October and November, a retail sales associate promotion ran in an effort to increase
appliance redemptions prior to Black Friday.

Two direct mail postcards promoting heat pumps and insulation were sent to approximately
1,100 customers in November.

New resource manuals, pocket guides and fact sheets were provided to retailers along with key
Home Energy Savings program information.

See ya later, refrigerator®
Newspaper ads for the See ya later, refrigerator® recycling program ran in Idaho Falls,
Pocatello and Rexburg papers during spring months. Digital ads through Yahoo and other
websites were also a part of the program communications.

Three inserts were included in Idaho residential customer bills (April, June and August).

In October, residential customers received a mailing with a refrigerator magnet encouraging
them to recycle their old refrigerators or freezers.

Energy FinAnswer & FinAnswer Express
Ads encouraging businesses and organizations to upgrade lighting in advance of changes in
federal fluorescent lighting standards ran in Idaho Falls and Pocatello newspapers and in the
Idaho Business Review in May and July. A new handout was also developed to educate
customers on the lighting standards changes.

On May 3, Idaho trade allies were invited to a breakfast to learn about the resources available to
help them save energy and money for themselves and their clients with the FinAnswer Express
program.
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Irrigation Load Control
Customers on Rate Schedule 10 received a mailing in February with information on the
prescheduled and dispatchable load control options. A follow up letter was sent in April to
inform customers of program modifications.

General Communications
Rocky Mountain Power included energy efficiency messages in radio, print and digital ads as
part of its ongoing Customer Awareness campaign that ran throughout the year.

Residential customers in Idaho received Rocky Mountain Power’s Voices newsletter in bills in
January, March, April, May, July, September, October and November. Each issue covered
energy efficiency information and tips as well as other service related topics.

Other newsletters such as Energy Insights, Energy Connections and Energy Update reach
community, business and government audiences on a quarterly or monthly basis. Newsletters
included energy efficiency stories geared toward commercial, industrial and agricultural
audiences.

Rocky Mountain Power has developed a variety of brochures and event materials with
information on energy efficiency programs and resources to help customers save money.

Customers can visit www.wattsmart.com for information on energy efficiency incentive
programs, tips and other resources to save energy and money. This information is also accessible
through our main website at www.rockymountainpower.net.

Rocky Mountain Power’s Idaho Twitter account (@RMP_Idaho) is used to promote energy
efficiency programs, recruit customers and inform customers with tips.

Additionally, Rocky Mountain Power’s wattsmart Facebook page (www.facebook.com/
rockymountainpower.wattsmart) points customers to energy efficiency programs and provides
conservation ideas.

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Peak Reduction Program and Activity

Peak Reduction programs assist the Company in balancing the timing of customer energy
requirements during heavy use hours; deferring the need for higher cost investments in delivery
infrastructure and generation resources that would otherwise be needed to serve those
requirements for a select few hours each year. These programs help the Company maximize the
efficiency of the Company’s existing electrical system and reduce costs for all customers.

Programs targeting capacity related resources are often specific to end use loads most prevalent
in a given jurisdiction, such as the agricultural pumping loads in the Company’s Idaho service
territory. The Company offers two peak reduction programs in Idaho; a pre-schedule and on-call
or dispatchable irrigation load control program. For the purpose of this report the two programs
are being combined and evaluated as one program.

Table 4: Load Management Portfolio Performance4
kW Under Control (Gross - At Gen) 281,362 Realized Load (Gross -At Gen) 178,850
kW Under Control (At Site) 258,000 Realized Load (At Site) 164,000
Total Expenditures 9,324,044$
Participation Credits 6,074,644$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness Pass Pass Pass Pass NA

4 Decrement values are considered confidential on load control programs. Cost effectiveness ratios and inputs will be available
under a protective agreement. A “Pass” designation equates to a benefit to cost ratio of 1 or better.
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Irrigation Load Control (Schedule 72 and 72A)

Irrigation Load Control (Schedules 72 & 72A) is offered to irrigation customers receiving
electric service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service.
Participants allow the curtailment of their electricity usage as prescribed in Schedules 72 and
72A in exchange for a participation credit. For most participants their irrigation equipment is set
up with a dispatchable two-way control system giving the Company control over their loads.
Participants are provided a day-ahead notification in advance of control events and have the
choice to opt-out of a limited number of dispatch events per season.

A summary of the program performance, expenditures, participation and cost effectiveness
results are provided in table 5:

Table 5: Irrigation Load Control Program Performance
MW Under Control (Gross - At Gen) 281.4 Realized Load 178.9
Expenditures - Total 9,324,044$
Participation Credits 6,074,644$
Program Operations Expense 3,249,400$
Participation (Customers) 235
Participation (Sites) 650
PTRC TRC UCT RIM PCT
Program Cost Effectiveness Pass Pass Pass Pass NA

Major Trends and Activities

The Irrigation Load Control Program was available for 52 hours from June 1 to August 31. The
program had the estimated potential to curtail 196 megawatts of load on July 18, the peak day.

In 2011 Rocky Mountain Power had three load control events. The first load control dispatch
was on June 29 and was estimated to reduce peak system load by 168 megawatts in Idaho. This
curtailment represented 69 percent of the potential 2455 megawatts of available load control
customer’s peak demand.

The second dispatch occurred on July 7 and was estimated to reduce system peak 160
megawatts. This curtailment represented 62 percent of the potential 2586 megawatts of available
load control customer’s peak demand.

The third dispatch was on July 11 and was estimated to reduce the system peak by 165
megawatts. This curtailment represented 64 percent of the potential 258 megawatts of available
load control customer’s peak demand.
Idaho load control events for 2011 achieved 62 percent to 69 percent of the available participant
peak load.

5 Demand fluctuates month to month. June’s undiversified demand for load control customers was 245 megawatts. 6 July’s undiversified demand for load control customers was 258 megawatts.
16

To comply with the settlement agreement approved by the Commission on April, 27, 2011,
Rocky Mountain Power studied the distribution system to determine which circuits were affected
the most by the Irrigation Load Control Program. It was determined that fourteen circuits on
seven substations were most susceptible to high voltage issues relating to the program. Rocky
Mountain Power engineered a solution to the problem by replacing manual capacitor banks with
automatic sensing capacitors that would turn on and off automatically to maintain acceptable
voltage levels. On these 14 circuits, 46 automatic switched capacitors were installed and 59
manual capacitors are being removed. This work is scheduled to be completed before the start of
the 2012 irrigation season.

Cost Effectiveness

The program was cost effective from all perspectives. Decrement values or avoided costs are
considered confidential on load control programs. Cost effectiveness ratios and inputs will be
available under a protective agreement. A “Pass” designation equates to a benefit to cost ratio of
1 or better.

Plans for 2012

The program will be implemented during 2012 in accordance with the Idaho Public Utilities
Commission Order 32235 dated April 27, 2011.

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Energy Efficiency Programs and Activity

Energy efficiency programs deliver sustainable energy savings by improving the efficiency of
equipment such as motors, lighting and cooling equipment. Energy efficiency is also delivered
through improved weatherization of existing buildings, improving the design features of new
facilities by ensuring they are constructed to exceed code. In the industrial sector, improvements
in industrial equipment or processes can also improve energy utilization and deliver long term
energy efficiency resources. Replacement of existing functional equipment, replacement of
equipment at the end of its useful life and improvement opportunities all provide opportunities to
deliver energy efficiency resources. While each type of opportunity has unique challenges,
improvements in these areas all deliver long term energy savings over the life of the installed
equipment.

To deliver resources from these different opportunities, the Company offers six energy efficiency
programs; three targeted to residential customers and three targeted to business customers. The
programs are designed to work in a coordinated fashion and provide complementary services
(i.e. recycle an existing refrigerator after buying a new Energy Star model) or different incentive
options (i.e., Energy FinAnswer incentives at the time a project is completed). Some programs or
program features are specifically designed to capture lost opportunities (the Design Assistance
provision in Energy FinAnswer), while other programs target retrofit or replacement
opportunities in existing structures (i.e., FinAnswer Express and Home Energy Savings).

Results for the 2011 Energy Efficiency Portfolio are presented in the following tables:

Table 6: Energy Efficiency Portfolio Performance

System Benefit Expenditures 2,363,302$
Energy Efficiency First Year Savings kWh/Yr (Gross at Generation) 9,660,007
Energy Efficiency First Year Savings kWh/Yr (at Site) 8,821,524
PTRC TRC UCT RIM PCT
Portfolio Cost Effectiveness 1.253 1.139 1.627 0.696 2.149
Levelized Cost ($/kWh) 0.0770$ 0.0770$ 0.0539$
Lifecycle Revenue Impact ($/kWh) 0.0000360$

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Table 7: Commercial & Industrial Energy Efficiency Portfolio

System Benefit Expenditures 1,346,069$
C&I Energy Efficiency First Year Savings kWh/Yr (Gross at Generation) 5,548,536
C&I Energy Efficiency First Year Savings kWh/Yr (at Site) 5,082,293
PTRC TRC UCT RIM PCT
Portfolio Cost Effectiveness 1.296 1.178 1.813 0.794 1.655
Levelized Cost ($/kWh) 0.0762$ 0.0762$ 0.0493$
Lifecycle Revenue Impact ($/kWh) 0.0000178$

Table 8: Residential Energy Efficiency Portfolio
System Benefit Expenditures 1,017,233$
Residential Energy Efficiency First Year Savings kWh/Yr (Gross at Generation) 4,111,471
Residential Energy Efficiency First Year Savings kWh/Yr (at Site) 3,739,231
PTRC TRC UCT RIM PCT
Portfolio Cost Effectiveness 1.202 1.093 1.413 0.588 3.221
Levelized Cost ($/kWh) 0.0780$ 0.0780$ 0.0604$
Lifecycle Revenue Impact ($/kWh) 0.0000232$

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Residential Energy Efficiency Programs and Activity

Home Energy Savings Program (Schedule 118)

The Home Energy Savings program (Schedule 118) provides a broad framework to deliver
incentives for more efficient products and services installed or received by Idaho customers in
new or existing homes, multi-family housing units or manufactured homes. The program is
delivered through a third party administrator hired by the Company. Program information is
available to the public at the program’s web site at
http://www.homeenergysavings.net/Idaho/idaho_home.html and can also be accessed through
http://www.rockymountainpower.net/env/epi.html, the Company’s Idaho energy efficiency
program website.

Summary of the program results for 2011 are provided in the table below:

Table 9: Home Energy Savings Program Performance
kWh/Yr Savings (Gross - At Gen) 2,797,917
kWh/Yr Savings (At Site) 2,544,602
Expenditures 613,890$
Incentives Paid 232,149$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness 1.476 1.342 2.115 0.689 2.511
Levelized Cost ($/kWh) 0.0640 0.0640 0.0406
Lifecycle Revenue Impact ($/kWh) 0.0000117$

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Details of 2011 measure level participation and savings are provided on the following table:

Table 10: Home Energy Savings Measure Performance
Home Energy Savings Measures
Unit
Measure
ment # of Units Participants
kWh/Yr
Savings
(Gross - At
Site)
Clothes Washer-Tier One (1.72 - 1.99 MEF) Units 14 14 3,188
Clothes Washer-Tier Two (2.0 + MEF) Units 1,165 1,165 283,193
Clothes Washer Recycling Units 0 0 0
Dishwasher Units 316 316 12,881
Evaporative Cooler (Portable) Units 0 0 0
Evaporative Coolers (Permanently Installed) Units 3 3 975
Electric Water Heater Units 58 58 5,261
Room AC Units 0 0 0
Refrigerator Units 350 350 34,125
Insulation - Attic sq feet 88,673 83 136,974
Insulation - Floor sq feet 969 3 6,439
Insulation - Wall sq feet 3,823 5 4,949
Windows sq feet 9,037 63 20,152
CAC (15 SEER) Projects 2 2 192
CAC Install Units 0 0 0
CAC Sizing Units 1 1 67
CAC Tune-Up Projects 1 1 30
Duct Sealing - Electric Projects 0 0 0
Duct Sealing - Gas Projects 0 0 0
Heat Pump Upgrade Projects 2 2 1,622
Heat Pump Conversion Units 4 4 12,588
HP Tune up Units 1 1 505
Ceiling Fans Units 17 11 1,819
Fixtures Units 110 40 10,120
CFL-Specialty Units 1,273 127 43,219
CFL-Twister Units 57,286 5,729 1,966,304
Totals 163,105 7,978 2,544,602
kWh/Yr Savings at Generation 2,797,917 (Note: CFL participation is assumed at 10 CFLs per participant.)

Major Trends and Activities

The Home Energy Savings program savings in 2011 decreased 78 percent in non-CFL measures
but increased 128 percent in CFL measures. This resulted in an overall decrease of 24 percent as
compared to 2010.

The largest decrease in non-CFL participation was seen in weatherization measures. The
contractor feedback indicated that overall sales were down compared to 2010 due to economic
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instability and very mild summer weather. Additionally, appliance sales slowed after the
exhaustion of American Recovery and Reinvestment Act of 2009 (ARRA) funds.

Special per bulb CFL pricing was instituted in 2011 which contributed to the achievement of 100
percent of lighting goals in Idaho by the end of the year. The program also partnered with Fluid
Market Strategies and the regional Simple Steps program that helped contribute to increased
savings of 816,000 kWh, which represents nearly 41 percent of lighting savings for 2011.

A marketing campaign, which provided incentives to the sales associates in order to drive
customer participation, was conducted in the last quarter of 2011. The campaign’s goal was to
promote appliance measures such as dishwashers, clothes washers and refrigerators and resulted
in a total of 135 applications received from the top retailers such as Sears, Denning’s, and Home
Depot. This promotion contributed significantly to appliance savings for the program. A similar
promotion will be considered again in 2012.

Cost Effectiveness

The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix 1 provides detailed inputs used in the cost effectiveness analysis of this program.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

Plans for 2012

The program is focusing on targeted retailer outreach in 2012, as six retailers in Idaho account
for 80 percent of appliance redemptions. Program staff is also focusing on the Qualified
Weatherization Contractor Network and bringing new trade allies onto the program. By co-
branding, placing product, and co-sponsoring promotions, the program expects to increase
participation.

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See ya later, refrigerator® (Schedule 117)

The Residential Refrigerator Recycling Program (Schedule 117) is available to Idaho residential
customers through a Company contracted third-party program administrator. Older refrigerators
and freezers which are less efficient, yet operational, are taken out of use permanently and
recycled in an environmentally responsible manner. The program’s objective is to permanently
retire these older and less efficient refrigerators and freezers from the market and recycle the
units in order to avoid their re-entry or resale on the secondary appliance market. Program
awareness is generated through mass media advertising channels as well as Company
communications such as the program’s web site, bill stuffers, and customer newsletters. In
addition to free pick-up and a nominal cash incentive, participants receive an energy efficiency
packet consisting of two ENERGY STAR®-certified compact fluorescent light bulbs, a
refrigerator/freezer thermometer, and energy education materials.

A summary of the program results for 2011 are provided in the table below.

Table 11: See ya later, refrigerator® Program Performance
kWh Savings (Gross - At Gen) 1,037,069
kWh Savings (At Site) 943,176
Expenditures 107,033$
Incentives Paid 21,300$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness 1.945 1.768 1.594 0.579 NA
Levelized Cost ($/kWh) 0.0418 0.0418 0.0464
Lifecycle Revenue Impact ($/kWh) 0.000006024$

Details of 2011 measure level participation and savings are provided on the following table:

Table 12: See ya later, refrigerator® Results
Refrigerator
Recycling Measure Unit Count
Per Unit Savings
(kWh/Yr)
Gross Savings
(kWh/Yr)
Refrigerator 542 1,149 622,758
Freezer 168 1,590 267,120
Total Units Recycled 710 889,878
Energy Savings Kits 658 81 53,298
Total (At Site) 943,176
Total (At Generation) 1,037,069

23
Major Trends and Activities

Program participation in 2011 decreased approximately 10 percent from 2010 (in terms of unit
volumes). A direct mail campaign in October involved approximately 20,000 pieces, and
resulted in strong Q4 program activity.

Environmental Attributes

In terms of the impact of the program on the environment, processing the 710 harvested units
resulted in the recycling of more than 44 tons of metal, 7 tons of plastics, 1 ton of tempered
glass, the recovery or destruction of more than 300 lbs of refrigerant, and the destruction of more
than 400 and 100 lbs of CFC-11 and HCFC-141b, respectively, contained in foam insulation.

Cost Effectiveness

The 2011 See ya later, refrigerator® program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix 1 provides detailed inputs used in the cost effectiveness
analysis of this program.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

Plans for 2012

Goals in 2012 call for 1,000 units to be collected and recycled. Based on successful experiences
in late 2010 and late 2011, direct mail will be used again in the May-June time frame. The retail
element, begun in 2011 at national chains such as Sears and Best Buy, will be expanded to
include R.C. Willey and stand-alone “mom and pop” stores. In addition, cross promotional
opportunities with the Home Energy Savings program will be used in retail stores (e.g., through
point-of-sale flyer placements).

24
Low Income Weatherization (Schedule 21)

The Low Income Weatherization Services program (Schedule 21) is available through a
partnership with Eastern Idaho Community Action Partnership (EICAP) in Idaho Falls and South
Eastern Idaho Community Action Agency (SEICAA) in Pocatello. These partnerships allow for
leveraging of Company funding with federal grants available to EICAP and SEICAA, increasing
the number of homes served. Rocky Mountain Power’s funding in 2011 provided rebates that
covered 85 percent of the cost of approved energy efficiency measures.

Income eligible households receive energy efficiency services at no cost. Participants can be
either homeowners or renters residing in single-family homes, manufactured homes and
apartments.

Table 13 summarizes the program results for 2011. Program expenditures totaled $253,809.
Funds received by the agency from other sources (state or federal funding) are not included.

Rocky Mountain Power’s program provided funding towards the weatherization of 100
qualifying homes in 2011 with an average program cost per home of $2,538.

25
Table 13: Low Income Weatherization Performance

kWh/yr Savings (At Site) 228,605
kWh/yr Savings (Gross - At Gen) 251,363
Expenditures 253,809$
Participation - Total # of Completed/Treated Homes 100
Number of Homes Receiving Specific Measures
Ceiling Insulation 37
Floor Insulation 30
Wall Insulation 6
Duct Insulation/Sealing 9
Attic Ventilation 29
Infiltration 57
Water Pipe Insulation and Sealing 88
Water Heater Repair 5
Water Heater Replacement 1
Furnace Repair/Tune-up 36
Furnace Replacement 6
Health & Safety 43
Replacement Windows 37
Thermal Doors 36
Compact Fluorescent Light Bulbs (CFLs) 97
Number of Specific Measures
Replacement Refrigerator 13
Total Program Costs PTRC TRC UCT RIM PCT
Program Cost Effectiveness 0.817 0.742 0.742 0.429 N/A
Levelized Cost ($/kWh) 0.1263 0.1263 0.1263
Lifecycle Revenue Impact ($/kWh) 0.000005332$
Results without additional data request costs PTRC TRC UCT RIM PCT
Program Cost Effectiveness 0.957 0.870 0.870 0.469 N/A
Levelized Cost ($/kWh) 0.1078 0.1078 0.1078
Lifecycle Revenue Impact ($/kWh) 0.000004542$
Major Trends and Activities

Weatherization completions in 2011 more than doubled compared to 2010 program activities.
The Low Income Weatherization Program tariff was revised as of December 28, 2010,
increasing the Company’s reimbursement from 75 percent of costs on approved measures to 85
percent, and annual funding was increased from $150,000 to $300,000.

26
Cost Effectiveness

An evaluation of Low Income Weatherization Services Optional for Income Qualifying
Customers program was completed in 2011 by a third party administrator for program years
2007 through 2009.

The Company recognizes the importance of the Low Income Weatherization Program and the
benefit to the customers by reducing kWh usage and helping to make participant’s bills more
affordable, as well as increasing their comfort. However, as described in the Low-Income
Weatherization program evaluation, due to many factors the third party evaluator determined that
the program was not cost-effective.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

Plans for 2012

We anticipate 2012 weatherization completions will be fairly consistent with 2011 results.

27
Conservation Education

Rocky Mountain Power committed to provide a total of $50,000 for an energy education
component for the Low Income Weatherization program (Schedule 21). This commitment was
made through a stipulation dated April 16, 2009, in Case No. PAC-E-08-01. The Company
provided $7,500 in funds for energy efficiency kits to be distributed through the Conservation
Education component in May, 2010, and a total of $42,500 in May, 2011 to Eastern Idaho
Community Action Partnership (EICAP) and South Eastern Idaho Community Action Agency
(SEICAA) to cover their expenses in providing these services.

The Conservation Education is designed to provide a group education session and an in-home
education session to participants, as well as an energy efficiency kit with easy-install measures.
The energy efficiency kits include one 13 watt CFL, one 19 watt CFL, one 23 watt CFL, ten
outlet gaskets, one kitchen aerator, one refrigerator temperature card and one luminescent night
light. The agencies began offering these services in May, 2011.

A total of 168 households completed the conservation education component in 2011. Since it is
designed to reach 500 households with the $50,000 funding, it is very likely these conservation
education services will continue through 2012 with the monies provided in 2010 and 2011.
Table 12 summarizes the program results for 2011. No savings are reported from behavioral
changes that may have resulted from the education sessions.

Table 14: Conservation Education
kWh/yr Savings (At Site) 22,848
kWh/yr Savings (Gross - At Gen) 25,123
Expenditures 42,500$
Completed households 168

Major Trends and Activities

The development of the curriculum and implementation of the conservation education
component for Rocky Mountain Power customers was delayed as staff from the Community
Action Partnership Association of Idaho (CAPAI), EICAP and SEICAA were focusing on the
implementation of the Idaho Power education program. These services were offered to our
customers beginning in May, 2011.

Plans for 2012

We anticipate that 2012 Conservation Education completions will be approximately the same as
in 2011 or greater. As of December 31, 2011, there were 332 kits remaining of the 500 Rocky
Mountain Power funded in 2010.

28
Non-Residential Energy Efficiency Programs and Activity

Energy FinAnswer (Schedule 125)

The Energy FinAnswer program is offered to commercial (buildings 20,000 square feet and
larger) and industrial customers. The program provides Company-funded energy engineering,
incentives of $0.12 per kWh of first year energy savings and $50 per kW of average monthly
demand savings up to a cap of 50 percent of the approved project cost. The program is designed
to target comprehensive projects requiring project specific energy savings analysis and operates
as a complement to the more streamlined FinAnswer Express program. In addition to customer
incentives, the program provides design team honorariums (a finder fee for new projects) and
design team incentives for new construction projects exceeding current Idaho energy code by at
least 10 percent.

A summary of the program results are provided in the table below:

Table 15: Energy FinAnswer Program
kWh/Yr Savings (Gross - At Gen) 532,135
kWh/Yr Savings (At Site) 487,927
Expenditures 154,367$
Incentives Paid 42,932$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness 1.657 1.507 1.928 0.857 2.615
Levelized Cost ($/kWh) 0.0563 0.0563 0.0440
Lifecycle Revenue Impact ($/kWh) 0.000001387$

Details of 2011 savings by type of measure are provided on the following table:

Table 16: Energy FinAnswer by Measure Type
Energy FinAnswer kWh/Yr Savings (at site) by Measure Type
Compressed Air 128,051 26%
Lighting 14,241 3%
Motors 302,120 62%
Refrigeration 43,515 9%
487,927
29
Major Trends and Activities

A total of 18 Energy FinAnswer projects were completed in 2011 compared to 10 in 2010.
Program specific energy savings decreased 67 percent and expenditures decreased 58 percent
during 2011 compared to 2010. The Company continues to market the program through its
Customer and Community Managers and network of trade allies in concert with the FinAnswer
Express program.

Cost Effectiveness

The 2011 Energy FinAnswer program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix 1 provides detailed inputs used in the cost effectiveness
analysis of this program.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

Plans for 2012

Continue to monitor actual and forecasted participation and assess the potential impacts of
program modifications similar to those implemented in other markets.

30
FinAnswer Express (Schedule 115)

The FinAnswer Express program (Schedule 115) is available to Idaho business customers
excluding those served on Schedule 10, which are eligible for program services through the
Irrigation Energy Savers program. The FinAnswer Express program is available to help
customers improve the efficiency of their new or replacement lighting, HVAC, motors, building
envelope and other equipment by providing prescriptive or pre-defined incentives for the most
common efficiency measures listed in the program incentive tables. The program also includes
custom incentives and technical analysis services for measures not listed in the program
incentive tables that improve electric energy efficiency. The program is designed to operate in
conjunction with the Energy FinAnswer program. Although incentives available vary, the
program provides incentives for both new construction and retrofit projects.

The program is primarily marketed through local trade allies who receive support from Company
provided sales and training team. The lists of participating vendors posted on the Company
website include 21 lighting, 32 HVAC, 27 motor, and 4 other equipment trade allies.

A summary of the program results are provided in the table below:

Table 17: FinAnswer Express Program7
kWh/Yr Savings (Gross - At Gen) 2,442,275
kWh/Yr Savings (At Site) 2,233,973
Expenditures 700,723$
Incentives Paid 356,726$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness 1.175 1.068 1.868 0.732 1.624
Levelized Cost ($/kWh) 0.0816 0.0816 0.0466
Lifecycle Revenue Impact ($/kWh) 0.0000155022$

Details of 2011 savings by type of measure are provided on the following table:

Table 18: FinAnswer Express by Measure Type
FinAnswer Express kWh/Yr Savings (at site) by Measure Type
Lighting 1,584,337 71%
Non-Lighting 649,636 29%
2,233,973

7 Savings and expenditures from school projects completed under the Idaho Office of Energy Resources Energy
Efficiency Incentives Agreement were removed from the PTRC, TRC and PCT cost effectiveness calculations and
results. See Appendix 1.
31

Major Trends and Activities

Participation from customers in the government and education sectors was strong in 2011,
accounting for almost 70 percent of program’s energy savings.

On May 3, 2011, Rocky Mountain Power provided lighting and mechanical/non-lighting
program training in combination with the Northwest Trade Ally Network (NW Tan) with
technical lighting training in Idaho Falls. Forty- one individuals attended the program training.

Cost Effectiveness

The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix 1 provides detailed inputs and assumptions used in the cost effectiveness analysis of
this program.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

Plans for 2012

The Company plans to continue to provide marketing and trade ally outreach to target customers
with T12 fluorescent lighting to provide information on changes in federal lighting standards
coming on July 14, 2012. Site outreach is continuing for trade allies with more resources and
field staff visiting the area including lighting technical specialists and non-lighting mechanical
outreach trade ally coordinators. These field visits are specifically designed to support the local
trade allies with project closure and processing the applications for incentives.

32
Agricultural Energy Services (Schedule 155)

Agricultural Energy Services, marketed as Irrigation Energy Savers (Schedule 155), was
available in 2011 to Idaho irrigation customers taking retail service on Schedule 10 through a
Company contracted third-party program administrator. The program design is intended to be the
energy efficiency complement to the Irrigation Load Control programs offered under Schedules
72 & 72A.

The 2011 program included the following customer service and measure components:
• Equipment Exchange – Provides new standard sprinkler nozzles, gaskets, and drains to
replace worn equipment on hand lines, wheel lines and solid set sprinklers systems.
• Pivot and Linear Equipment Upgrades – Incentives are provided for certain pivot and
linear system measures including sprinkler packages, pressure regulators, and drains. The
list of prescriptive incentives is not designed to be exhaustive and other pivot measures
are eligible for incentives if energy savings can be calculated and the customer incurs
costs to make the changes.
• System Consultation – This service provides a simple site specific audit of a customer’s
irrigation system to promote irrigation water management and identify energy savings
opportunities. This consultation provides information prior to a full pump test.
• Pump Testing – The pump test includes directly measuring pump lift, flow, pressure, and
electrical demand and is performed after the pump has been screened and the owner’s
financial investment criteria understood.
• System Analysis – The program provides energy engineering to help growers quantify
the costs and savings of their system efficiency upgrades. Often these upgrade decisions
are made in conjunction with operational production change considerations impacting a
growers equipment needs. Incentives are based on a standard formula tied to costs and
first year energy savings.

A summary of the program results for 2011 are provided in the table below.

Table 19: Agricultural Energy Services Program
kWh/Yr Savings (Gross - At Gen) 2,574,126
kWh/Yr Savings (At Site) 2,360,393
Expenditures 490,980$
Incentives Paid 224,890$
PTRC TRC UCT RIM PCT
Program Cost Effectiveness 1.381 1.255 1.743 0.899 1.506
Levelized Cost ($/kWh) 0.0757 0.0757 0.0545
Lifecycle Revenue Impact ($/kWh 0.0000046450$
33
Details of 2011 savings by type of measure are provided on the following table:

Table 20: Agricultural Energy Savers by Measure8
Agricultural Energy Savers kWh/Yr Savings by Measure Type (at Site)
Equipment Exchange & Pivot/Linear Upgrade 1,697,132 72%
System Design 663,259 28%
2,360,391

Major Trends and Activities

The 2011 savings and expenses were 6 percent and 23 percent, respectively, lower compared to
2010 program savings and expenditures.

During 2011, 101 site visits were completed to obtain system information used in either a system
consultation or an energy analysis evaluation as a part of the Agricultural Energy Services
Program. During the same year, 21 post installation inspections were completed to verify project
installation and energy savings.

The following outreach and event activities were completed for the program in 2011:

• Maintained a booth at the Eastern Idaho Ag. Expo and Potato School January 18 – 20, to
promote the program and provide program information to customers.
• Maintained a booth and met with customers at the Rain For Rent customer appreciation
day in Idaho Falls on February 24.
• Maintained a booth and met with customers at the Valley Implement customer
appreciation day in Preston on February 24.
• Met with each of the program participating dealers and provided a summary report of
incentives provided to their customers through the program, provided updated program
applications and information, and answered program related questions.

Cost Effectiveness

The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix 1 provides detailed inputs and assumptions used in the cost effectiveness analysis of
this program.

Program Evaluation

See comments under the Program Evaluation heading in the 2011 Performance and Activities
section of this report for evaluation activities related to this program.

8 Table totals may not add up exactly due to rounding
34
Summary of 2011 Results

Table 21: Revenues (Schedule 191) by Customer Type

Table 22: Expenditures (Schedule 191) by Customer Type
(Note – Table 22 does not include Irrigation Load )
Residential
47%
Commercial
26%
Industrial
8%Agricultural
19%

Residential
43%
Commercial
21%
Industrial
8%
Irrigation
27.5%
Public
Street &
Highway
0.5%

35
Table 23: Energy Efficiency kWh Saved by Customer Type

Residential
43%
Commercial
25%
Industrial
5%
Irrigation
27%

36
Balancing Account Summary

Energy efficiency and peak reduction activities are funded by revenue collected through
Schedule 191, Customer Efficiency Services Rate on customer bills. Expenses for energy
efficiency programs are charged as incurred and booked to the balancing account. The
balancing account activity for 2011 is outlined in the table below.

Table 24: Balancing Account Activity (Schedule 191)
Balance as of 12/31/10
3,845,843$
Monthly Program
Cost - Fixed Assets Accrued Costs Rate Recovery
Carrying
Charge
Cash Basis
Accumulated Balance
ccrual Basis
Accumulated
Balance
January 94,913.02$ - (418,081.55)$ 3,070.00$ 3,525,744.00$ -
February 222,587.37$ - (338,071.76)$ 2,890.00$ 3,413,149.61$ -
March 242,913.84$ - (310,853.16)$ 2,816.00$ 3,348,026.29$ -
April 213,813.93$ - (284,248.86)$ 2,761.00$ 3,280,352.36$ -
May 174,180.12$ - (351,043.79)$ 2,660.00$ 3,106,148.69$ -
June 193,591.58$ - (455,326.01)$ 2,479.00$ 2,846,893.26$ -
July 138,269.01$ - (785,015.77)$ 2,103.00$ 2,202,249.50$ -
August 220,093.03$ - (719,628.69)$ 1,627.00$ 1,704,340.84$ -
September 184,203.33$ - (570,028.01)$ 1,260.00$ 1,319,776.16$ -
October 103,080.76$ - (389,845.34)$ 980.00$ 1,033,991.58$ -
November 255,997.43$ - (353,022.44)$ 821.00$ 937,787.57$ -
December 626,340.83$ 380,980.18 (381,809.72)$ 883.00$ 1,183,201.68$ 1,564,181.86
2010 totals 2,669,984.25$ 380,980.18$ (5,356,975.10)$ 24,350.00$

Column Explanations:
Monthly Program Costs – Fixed Assets: Monthly expenditures for all energy efficiency and peak reduction
program activities.
Accrued Costs: Program costs incurred during the period not yet posted.
Rate Recovery: Revenue collected through Schedule 191, Customer Efficiency Service Rate.
Carrying Charge: Monthly “interest” charge based on “Accumulated Balance” of the account. The current
“interest rate” for the Accumulated Balance is 1 percent per year.
Accumulated Balance: Current balance of the account. A running total of account activities. If more is
collected in “Revenue” than is spent for a given month, the “Accumulated Balance” will be decreased by
the net amount. A negative accumulative balance means cumulative revenue exceeds cumulative
expenditures; positive accumulative balance means cumulative expenditures exceed cumulative revenue.
Accrual Basis Accumulative Balance: Current balance of account including accrued costs.

At the beginning of 2011, the unfunded balance was approximately $3.846 million and decreased
by approximately $2.282 million during the year. The unfunded balance at the end of 2011 is
$1.564 million which includes the accrued cost.
37
Cost Effectiveness

Introduction

The cost effectiveness of individual programs operated by the Company for 2011 are calculated
using actual expenditures and reported savings. Cost-effectiveness is provided at the individual
program, load management portfolio, residential energy efficiency portfolio, non-residential
energy efficiency portfolio, combined energy efficiency portfolio, and overall energy efficiency
and peak reduction program portfolio levels. Deemed savings estimates where applicable were
the same as those used in the planning estimates.

Energy savings shown in this report are gross savings and the impact of line losses is indicated
with an at “site” or at “generation” designation. Line losses are based on the Company’s 2007
line loss study. Net-to-gross assumptions are consistent with planning estimates. The energy
savings attributed to each program are shaped according to specific end-use savings (the hourly
calculation of when energy is used for the various end-use measures from which the savings are
derived). Program costs and the value of the energy savings are then compared on a present
value basis with the Company’s 2011 Integrated Resource Plan (IRP) calculated decrement
values for energy efficiency resource savings and avoided capacity investments. The energy
efficiency resource decrement values are fully shaped to represent the 8,760 hourly values that
exist within a calendar year. By matching the hourly savings with the hourly avoided costs, both
energy and capacity impacts of energy efficiency savings are recognized.

The cost/benefit analysis of the load management programs are based on the avoided value of
peak or capacity investments. For purposes of calculating program cost-effectiveness no energy
savings are included for the load management programs, only a shift of when the energy is used
away from the peak load hours. The five California Standard Practice Manual cost effectiveness
tests were utilized in the cost benefit analysis for both energy efficiency and load management
programs. Further details are available in Appendix 1.

38
Key Assumptions for Cost Effectiveness Calculations:
Cost Effectiveness calculations for programs and measures (or measure groups) within each
program will be detailed in the tables in Appendix 1.

Global Assumptions used in all cost effectiveness calculations include:

Key elements that go into the cost effectiveness calculation for each program include:

• KW/kWh Savings Gross
• Administrative Expenses
• Incentives Paid
• Total Utility Costs – including administration and evaluation
• Gross Customer Costs
• Net To Gross Ratio
• Measure Life
• Avoided Cost/Resource Decrement Value

Please reference Appendix 1, Cost Effectiveness 2011 Idaho Energy Efficiency and Peak
Reduction Annual Report for additional information on the key assumptions and inputs for cost
effectiveness calculations for each program.

Assumption Value Source
Discount Rate 7.17%2011 Integrated Resource Plan
Line Losses (Idaho Specific)
Residential 9.955%2007 MAC Line Loss Study
Commercial 9.326%2007 MAC Line Loss Study
Industrial 9.055%2007 MAC Line Loss Study
39
Appendices:

Appendix 1 – Cost Effectiveness 2011 Idaho Energy Efficiency and Peak Reduction
Annual Report

Appendix 2 – 2011 Idaho Irrigation Post Peak Report

Appendix 1
Cost Effectiveness
2011 Idaho Energy Efficiency and Peak
Reduction Annual Report

Rocky Mountain Power

2
Table of Contents 
Portfolio and Sector Level Cost Effectiveness ............................................................................... 3 
Program Level Cost Effectiveness .................................................................................................. 5 
Home Energy Savings Program – Schedule 118 ........................................................................ 5 
Refrigerator Recycling (See ya later, refrigerator®) – Schedule 117 ......................................... 6 
Low Income Weatherization – Schedule 21 ............................................................................... 7 
Energy FinAnswer – Schedule 125 ............................................................................................. 9 
FinAnswer Express – Schedule 115 ......................................................................................... 10 
Agricultural Energy Services (Irrigation Energy Savers) – Schedule 155 ............................... 12 

3
Portfolio and Sector Level Cost Effectiveness

The overall energy efficiency and peak reduction portfolio and component sectors were all cost
effective on a PacifiCorp Total Resource Cost Test (PTRC), Total Resource Cost Test (TRC),
Utility Cost Test (UCT), Ratepayer Impact Test (RIM) and Participant Cost Test (PCT) basis.

Decrement values are considered confidential on load control programs. Cost effectiveness ratios
and inputs will be available under a protective agreement. A “Pass” designation equates to a
benefit to cost ratio of 1 or better.

The following table provides the results of all five cost effectiveness tests.

Sector and Program Level Cost Effectiveness Summaries:

The cost effectiveness results for the sector level are aggregations of the costs and benefits from
the component programs. The inputs and assumptions that support these results are contained in
the program level cost effectiveness results.

2011 Total Portfolio Energy Efficiency

Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0770 $3,346,269 $4,194,207 $847,938 1.253
Total Resource Cost Test (TRC) No
Adder 0.0770 $3,346,269 $3,812,916 $466,647 1.139
Utility Cost Test (UCT) 0.0539 $2,531,717 $4,119,958 $1,588,241 1.627
Rate Impact Test (RIM) $5,917,306 $4,119,958 ($1,797,348) 0.696
Participant Cost Test (PCT) $2,232,929 $4,799,498 $2,566,569 2.149
Lifecycle Revenue Impacts ($/kWh) $0.0000359843

2011 Portfolio and Sector Cost Effectiveness Summary
Cost Effectiveness Test
PTRC TRC UCT RIM PCT
2011 Total Portfolio including Load Control 4.354 3.958 2.228 1.733 4.870
2011 Total Energy Efficiency Portfolio 1.253 1.139 1.627 0.696 2.149
2011 C&I Energy Efficiency Portfolio 1.296 1.178 1.813 0.794 1.655
2011 Residential Energy Efficiency Portfolio 1.202 1.093 1.413 0.588 3.221
2011 Irrigation Load Control Pass Pass Pass Pass A
4

2011 C&I Energy Efficiency Portfolio

Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0762 $1,830,179 $2,371,120 $540,941 1.296
Total Resource Cost Test (TRC) No
Adder 0.0762 $1,830,179 $2,155,564 $325,385 1.178
Utility Cost Test (UCT) 0.0493 $1,358,529 $2,462,606 $1,104,077 1.813
Rate Impact Test (RIM) $3,100,143 $2,462,606 ($637,537) 0.794
Participant Cost Test (PCT) $1,527,679 $2,527,670 $999,991 1.655
Lifecycle Revenue Impacts ($/kWh) $0.0000178050

2011 Residential Energy Efficiency Portfolio

Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC)
+ Conservation Adder 0.0780 $1,516,090 $1,823,087 $306,997 1.202
Total Resource Cost Test (TRC)
No Adder 0.0780 $1,516,090 $1,657,352 $141,262 1.093
Utility Cost Test (UCT) 0.0604 $1,173,188 $1,657,352 $484,164 1.413
Rate Impact Test (RIM) $2,817,163 $1,657,352 ($1,159,811) 0.588
Participant Cost Test (PCT) $705,249 $2,271,828 $1,566,578 3.221
Lifecycle Revenue Impacts ($/kWh) $0.0000232203

5

Program Level Cost Effectiveness
Home Energy Savings Program – Schedule 118

The tables below present the cost-effectiveness findings of the Idaho Home Energy Savings
program based on Rocky Mountain Power’s 2011 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 IRP 35% east residential whole house load factor
decrement.
Table 1: Home Energy Savings
Annual Program Costs
Program Management
and Administration
Other Program Costs Incentives Total Utility
Costs
Net Participant
Incremental
Cost
Lighting $8,389 $962 $56,864 $66,216 $264,836
Appliance $219,494 $25,176 $136,216 $380,886 $267,439
Home Improvement $105,210 $12,068 $36,119 $153,397 $44,886
HVAC $9,368 $1,074 $2,950 $13,392 $8,436
Total $342,461 $39,281 $232,149 $613,891 $585,597
Table 2: Home Energy Savings
Savings by Measure Type
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Lighting 2,009,524 103% 2,069,809 85% 1,759,338 5.0
Appliance 351,561 161% 566,013 86% 486,771 14.0
Home Improvement 168,514 75% 126,385 87% 109,955 30.0
HVAC 15,004 99% 14,854 86% 12,774 14.0
Total 2,544,602 95% 2,777,062 86% 2,368,839
Table 3: IRP 35% Load Factor Decrement
All Measures AC: IRP 35% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0640 $967,338 $1,428,143 $460,806 1.476
Total Resource Cost Test (TRC) No
Adder 0.0640 $967,338 $1,298,312 $330,974 1.342
Utility Cost Test (UCT) 0.0406 $613,890 $1,298,312 $684,422 2.115
Rate Impact Test (RIM) $1,884,943 $1,298,312 ($586,631) 0.689
Participant Cost Test (PCT) $683,949 $1,717,612 $1,033,663 2.511
6
Lifecycle Revenue Impacts ($/kWh) $0.0000117448
Discounted Participant Payback (years) 1.93

Refrigerator Recycling (See ya later, refrigerator®) – Schedule 117

The tables below present the cost-effectiveness findings of the Idaho See-Ya-Later Refrigerator
program based on Rocky Mountain Power’s 2011 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 IRP 35% east residential whole house load factor
decrement.
Table 1: See-Ya-Later
Annual Program Costs
Marketing and
Program
Development
Utility Admin Program
Management and
Administration
Incentives Total Utility
Costs
Net Participant
Incremental
Cost
Refrigerators $995 $5,178 $56,730 $16,260 $79,163 $7,902
Freezers $286 $1,488 $16,301 $5,040 $23,115 $2,853
Kits $75 $391 $4,289 $0 $4,756 $0
Total $1,357 $7,057 $77,320 $21,300 $107,033 $10,755

Table 2: See-Ya-Later
Savings by Measure Type
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Refrigerators 622,758 103% 641,441 49% 311,740 5.00
Freezers 267,120 69% 184,313 57% 104,321 5.00
Kits 53,298 91% 48,501 100% 48,501 6.60
Total 943,176 93% 874,255 53% 464,562

Table 3: IRP 35% Load Factor Decrement
All Measures AC: IRP 35% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0418 $96,489 $187,671 $91,182 1.945
Total Resource Cost Test (TRC) No Adder 0.0418 $96,489 $170,610 $74,121 1.768
Utility Cost Test (UCT) 0.0464 $107,034 $170,610 $63,576 1.594
Rate Impact Test (RIM) $294,767 $170,610 ($124,157) 0.579
Participant Cost Test (PCT) $21,300 $369,026 $347,726 17.325
7
Lifecycle Revenue Impacts ($/kWh) $0.000006024
Discounted Participant Payback (years) 0.22
Low Income Weatherization – Schedule 21

The tables below present the cost-effectiveness findings of the Idaho Low Income
Weatherization program based on Rocky Mountain Power’s 2011 costs and savings estimates.
The Utility discount rate is from the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 medium IRP 35% east residential whole house load
factor decrement. The results for a second scenario with reduced evaluation costs are also
presented below.
Table 1: Low Income Weatherization
Annual Program Costs
Utility Admin Administration Evaluation Incentives Total Utility
Costs
Net Participant
Incremental Cost
Low Income weatherization $15,941 $200,719 $37,150 $0 $253,809 $0

Table 2: Low Income Weatherization
Annual Program Costs – Reduced Data Request Costs
Utility Admin Administration Evaluation Incentives Total Utility
Costs
Net Participant
Incremental Cost
Low Income weatherization $15,941 $200,719 $7 $0 $216,666 $0

Table 3: Low Income Weatherization
Savings by Measure Type
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Low Income weatherization 228,605 65% 148,593 100% 148,593 25.00

Table 4: Low Income Weatherization
All Measures AC: IRP 35% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.1263 $253,809 $207,273 ($46,536) 0.817
Total Resource Cost Test (TRC) No Adder 0.1263 $253,809 $188,430 ($65,379) 0.742
Utility Cost Test (UCT) 0.1263 $253,809 $188,430 ($65,379) 0.742
Rate Impact Test (RIM) $438,998 $188,430 ($250,568) 0.429
Participant Cost Test (PCT) $0 $185,189 $185,189 N/A
8
Lifecycle Revenue Impacts ($/kWh) $0.0000053322
Discounted Participant Payback (years) N/A
Table 5: Low Income Weatherization with Reduced Data Request Costs
All Measures AC: IRP 35% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.1078 $216,666 $207,273 ($9,393) 0.957
Total Resource Cost Test (TRC) No Adder 0.1078 $216,666 $188,430 ($28,236) 0.870
Utility Cost Test (UCT) 0.1078 $216,666 $188,430 ($28,236) 0.870
Rate Impact Test (RIM) $401,855 $188,430 ($213,425) 0.469
Participant Cost Test (PCT) $0 $185,189 $185,189 N/A
Lifecycle Revenue Impacts ($/kWh) $0.0000045418
Discounted Participant Payback (years) N/A

9

Energy FinAnswer – Schedule 125

The tables below present the cost-effectiveness findings of the Idaho Energy FinAnswer program
based on Rocky Mountain Power’s 2011 costs and savings estimates. The Utility discount rate is
from the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 IRP 69% east system load factor decrement.
Table 1: Energy FinAnswer
Annual Program Costs
Evaluation Engineering
Costs
Utility Admin Administration Incentives Total Utility
Costs
Net
Participant
Incremental
Cost
Commercial $0 $10,531 $5,057 $1,547 $1,167 $18,303 $3,688
Industrial $0 $67,564 $22,954 $3,781 $41,765 $136,064 $82,447
Total $0 $78,095 $28,012 $5,328 $42,932 $154,367 $86,135

Table 2: Energy FinAnswer
Savings by Measure Type
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Commercial 9,727 91% 8,852 75% 6,639 15
Industrial 478,200 91% 435,162 75% 326,372 15
Total 487,927 91% 444,014 75% 333,010

Table 3: IRP 69% Load Factor Decrement
All Measures AC: IRP 69% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0563 $197,570 $327,460 $129,891 1.657
Total Resource Cost Test (TRC) No Adder 0.0563 $197,570 $297,691 $100,122 1.507
Utility Cost Test (UCT) 0.0440 $154,367 $297,691 $143,324 1.928
Rate Impact Test (RIM) $347,371 $297,691 ($49,679) 0.857
Participant Cost Test (PCT) $114,846 $300,270 $185,424 2.615
Lifecycle Revenue Impacts ($/kWh) $0.0000013874
Discounted Participant Payback (years) 3.17

10
FinAnswer Express – Schedule 115

The tables below present the cost-effectiveness findings of the Idaho FinAnswer Express
program based on Rocky Mountain Power’s 2011 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 IRP 69% east system load factor decrement.
Table 1a: FinAnswer Express
Annual Program Costs – RIM and UCT Perspectives
Evaluation Engineering
Costs
Utility Admin Administration Incentives Total Utility
Costs
Net Participant
Incremental Cost
Commercial $182 $67,063 $44,644 $166,233 $354,692 $632,813 $1,311,514
Industrial $1,298 $4,051 $8,165 $52,362 $2,034 $67,910 $5,820
Total $1,480 $71,113 $52,809 $218,595 $356,726 $700,723 $1,317,334

Table 1b: FinAnswer Express
Annual Program Costs – PTRC, TRC, and PCT Perspectives
Evaluation Engineering
Costs
Utility Admin Administration Incentives Total Utility
Costs
Net Participant
Incremental Cost
Commercial $182 $67,063 $34,153 $127,168 $278,438 $507,003 $638,226
Industrial $1,298 $4,051 $8,165 $52,362 $2,034 $67,910 $5,820
Total $1,480 $71,113 $42,318 $179,530 $280,472 $574,913 $644,046
Table 2a: FinAnswer Express
Savings by Measure Type – RIM and UCT Perspectives
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Commercial 2,219,662 96% 2,130,876 76% 1,619,465 12
Industrial 14,311 96% 13,739 76% 10,441 12
Total 2,233,973 2,144,614 1,629,907

Table 2b: FinAnswer Express
Savings by Measure Type – PTRC, TRC, and PCT Perspectives
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Commercial 1,695,962 96% 1,628,124 76% 1,237,374 12
Industrial 14,311 96% 13,739 76% 10,441 12
Total 1,710,273 1,641,862 1,247,815
11
Table 3: IRP 69% Load Factor Decrement
All Measures AC: IRP 69% LF Decrement
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0816 $938,487 $1,102,393 $163,906 1.175
Total Resource Cost Test (TRC) No Adder 0.0816 $938,487 $1,002,175 $63,688 1.068
Utility Cost Test (UCT) 0.0466 $700,723 $1,309,218 $608,495 1.868
Rate Impact Test (RIM) $1,788,881 $1,309,218 ($479,664) 0.732
Participant Cost Test (PCT) $847,429 $1,376,046 $528,617 1.624
Lifecycle Revenue Impacts ($/kWh) $0.0000155022
Discounted Participant Payback (years) 5.30

Cost Effectiveness Inputs at the Measure Level

Rocky Mountain Power and Idaho Office of Energy Resources (OER) has an Energy Efficiency
Incentive Agreement in place for completion of public school projects. The Agreement provides
for a cooperative relationship to maximize the use of federal funding to promote and execute
additional cost effective energy efficiency measures in public schools within the Company’s
territory. Because the participant costs reflected total project costs which included non
incentivized measures from the Company. All associated costs and energy savings from the
school programs were removed from cost effectiveness tests for PTRC, TRC and PCT
perspectives

12
Agricultural Energy Services (Irrigation Energy Savers) – Schedule 155

The tables below present the cost-effectiveness findings of the Idaho Agriculture program based
on Rocky Mountain Power’s 2011 costs and savings estimates. The Utility discount rate is from
the 2011 Integrated Resource Plan (IRP).

Cost-effectiveness was tested using the 2011 medium IRP 20% east system commercial cooling
load factor decrement.
Table 1: Agriculture
Annual Program Costs
Marketing and
Program
Development
Utility
Admin
Administration Evaluation Incentives Total Utility
Costs
Net Participant
Incremental
Cost
Equipment Exchange &
Pivot/Linear Upgrade $1,753 $16,104 $172,796 $667 $143,198 $334,518 $207,940
System Design $685 $6,294 $67,531 $261 $81,692 $156,462 $207,632
Total $2,438 $22,398 $240,326 $928 $224,890 $490,980 $415,572

Table 2: Agriculture
Savings by Measure Type
Gross kWh
Savings
Realization
Rate
Adjusted
Gross
Savings
Net to Gross
Percentage
Net kWh
Savings
Measure
Life
Equipment Exchange &
Pivot/Linear Upgrade 1,697,132 100% 1,697,132 74% 1,247,392 5.00
System Design 663,259 100% 663,259 74% 487,495 7.00
Total 2,360,391 2,360,391 1,734,888

Table 3: IRP 20% Commercial Cooling Load Factor Decrement
All Measures AC: IRP 20% Commercial
Cooling
Levelized
$/kWh Costs Benefits Net Benefits
Benefit/Cost
Ratio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0757 $681,662 $941,267 $259,605 1.381
Total Resource Cost Test (TRC) No Adder 0.0757 $681,662 $855,697 $174,035 1.255
Utility Cost Test (UCT) 0.0545 $490,980 $855,697 $364,718 1.743
Rate Impact Test (RIM) $951,431 $855,697 ($95,734) 0.899
Participant Cost Test (PCT) $565,404 $851,354 $285,950 1.506
Lifecycle Revenue Impacts ($/kWh) $0.0000046450
Discounted Participant Payback (years) 2.82

(Proprietary and Confidential)

2011 Idaho Irrigation Post Peak Report

Executive Sponsor
Douglas N. Bennion, P.E.

Study Team
Manager
Kevin W. Thompson

Principal Authors
Mike Anderson
Jake Barker
Bill Comeau
Tony Perkins

Contributors
Scott Murdock
Susan Smith
Nathan Wilson

November 2011
Photograph courtesy USDA NRC
   2011 Idaho Irrigation Post Report

Field Engineering Page 1 of 19 11/2011

~~ROCKY MOUNTAIN POWER
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   2011 Idaho Irrigation Post Report

Field Engineering Page 2 of 19 11/2011

Table of Contents
EXECUTIVE SUMMARY .......................................................................................................................4
SYSTEM LOAD DATA ANALYSIS .......................................................................................................5
Idaho system load data analysis ...............................................................................................................5
Idaho irrigation load .................................................................................................................................5
Geographic Area ......................................................................................................................................5
Crops load detail .......................................................................................................................................8
Idaho Weather ..........................................................................................................................................9
Idaho Transmission System ...................................................................................................................10
IRRIGATION LOAD CONTROL PROGRAM DETAILS ...............................................................11
Review of Program Results ...................................................................................................................11
Load control events in 2011 ...............................................................................................................11
System Concerns with Irrigation Program ............................................................................................15
Voltage issues System Optimization .................................................................................................15
Harmonic issues .................................................................................................................................17
CONCLUSIONS .....................................................................................................................................19

   2011 Idaho Irrigation Post Report

Field Engineering Page 3 of 19 11/2011

~~ROCKY MOUNTAIN POWER
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   2011 Idaho Irrigation Post Report

Field Engineering Page 4 of 19 11/2011

EXECUTIVE SUMMARY
Rocky Mountain Power conducts an Idaho post peak irrigation system review to understand the impacts
of Idaho irrigation load, and in particular the impact of the Idaho Irrigation Load Control Program. This
annual report communicates the findings, conclusions, and recommendations resulting from the review.
First, the 2011 report analyzes system load data and irrigation load patterns during the 2011 irrigation
season (May 1 through August 31). It discusses total Rocky Mountain Power Idaho load versus Idaho
irrigation load, and irrigation load control program participants’ load versus non-participants’ load. In
addition, it discusses how crop rotations and weather affect irrigation, and summarizes the transmission
system load in heavy use irrigation areas.
Second, the report analyzes the demand side management Irrigation Load Control Program and the
affects the program has on the transmission and distribution system. It discusses the details of the three
dispatch events for 2011 and some of the system concerns with the program, including voltage and
harmonic issues. Along with the concerns are resolutions that are being implemented or recommended.
Finally, the report identifies a number of informational conclusions and a few recommendations.
Some of the key informational points from the report are:
• Irrigation load in Idaho represents 42% of the State total peak load.
• Idaho has just over 4,700 irrigation customers and 45% of these customers participate in the
Irrigation Load Control Program. The program was dispatched three times in 2011 and is
estimated to have curtailed an average of 164 megawatts each time.
• In 2008 the company started noticing high voltage swings on the distribution system
whenever the Irrigation Load Control Program was dispatched. A project was initiated in
2011 with work anticipated to be completed by April 2012. As a result, in 2011 the company
worked with irrigators to limit load on distribution circuits with voltage concerns. To address
the problem, a settlement was reached with the Idaho Commission staff, the Idaho Irrigation
Pumper Association, and Rocky Mountain Power. The settlement stated that Rocky
Mountain Power would invest a minimum of $1.3 million before the 2012 irrigation season
to alleviate known voltage issues.
   2011 Idaho Irrigation Post Report

Field Engineering Page 5 of 19 11/2011

SYSTEM LOAD DATA ANALYSIS
Idaho Irrigation Load
Irrigated agricultural land in southeastern Idaho served by Rocky Mountain Power is primarily in the
Snake River Plain. This area is an inverted triangle shape from Shelley on the south to Dubois on the
northwest and Ashton on the northeast; Arco on the west to Ririe (northeast of Idaho Falls) on the east.
Other areas in Idaho with irrigation agricultural land served by Rocky Mountain Power are: Preston,
Malad, Marsh Valley, Montpelier, and in the Gem Valley around Grace, Bancroft and Chesterfield
(Figure 1). These other areas have much less irrigation load than the primary area in the Snake River
Plain.

Irrigation water comes from either surface water—rivers, canals, ditches—or groundwater from wells.
The irrigation customers connected to the Rocky Mountain Power system use pumps driven by electric
motors to move water from the source, and pressurize it into an irrigation system. Electric pump motor
sizes reach 1000 horsepower.
The larger pump motors are used for drawing groundwater out of some of the deep wells in the area.
Irrigation systems can be a center pivot system1 (Figure 2), a wheel line2 (Figure 3), or hand lines3

1 A pipe with sprinklers carried by wheeled towers in an arc around a center point. 2 A pipe with sprinklers attached on large wheels that is moved in a line across a field. 3 Pipes with sprinklers attached that are laid in a line on the ground.
Figure 1. Geographic Area
   2011 Idaho Irrigation Post Report

Field Engineering Page 6 of 19 11/2011

(Figure 4). A center pivot system will run continuously for the time it takes for a complete cycle, usually
hours or days. Wheel lines and hand lines will run for 8 to 24 hours then be turned off to be moved
manually.
On the 2011 Idaho system peak day, July 18th, Rocky Mountain Power’s Idaho load4 was 770
megawatts. On this day, it is estimated 76% of the irrigation customers in the load control program with
controllable devices were operating. For purposes of this report it is assumed the total irrigation
population in Idaho operated at a 76% diversity factor on the peak day. Using customer account data,
there was 428 megawatts of Idaho irrigation undiversified demand in July. Applying the 76% diversity
factor against the 428 megawatts of demand, yields 325 megawatts of total Idaho irrigation load and 445
megawatts of non-irrigation load on the peak day (Figure 5).

Figure 5. Idaho System Loading

4 Idaho load was 12% of the Rocky Mountain Power total system load
58%
42%
Idaho System Loading 07‐18‐2011*
Non‐Irrigation Load, 445 MW Irrigation Load: 325 MW
Figure 2. Typical Center Pivot Figure 3. Typical Wheel Line –
Photograph courtesy USDA NRCS
Figure 4. Typical Hand Line –
Photograph courtesy USDA ERS
   2011 Idaho Irrigation Post Report

Field Engineering Page 7 of 19 11/2011

Rocky Mountain Power had 4,765 irrigation customers connected in the State of Idaho in 2011. The
undiversified average demand for these 4,765 irrigation customers was 428 megawatts in July 2011. Of
these 4,765 customers there are 2,165, or 45%, that participate in the company’s Irrigation Load Control
Program (Figure 6).   
In July, the total undiversified demand of customers participating in the load control program was 258
megawatts. Applying the same 76% diversity factor from above to these 258 megawatts yields 196
megawatts of diversified load from customers participating in the load control program in July.
Therefore on the peak day—July 18th—of the 325 megawatts of total irrigation load in Idaho, 196
megawatts of load was utilized by load control program participants, and 129 megawatts was utilized by
non-participants (Figure 7).

Figure 7. Idaho Irrigation Customer load
40%
60%
Idaho Irrigation Customer Load
Non‐Load Controlled: 129 MW Load Controlled: 196 MW
55%
45%
Idaho Irrigation Customers
Total non Load Control Irrigation Customers
Total Number of Irrigation Load Control Customers
Figure 6. Idaho Irrigation Customers
   2011 Idaho Irrigation Post Report

Field Engineering Page 8 of 19 11/2011

Idaho and Utah Crops Load Detail
The primary crops grown in the Rocky Mountain Power service territory in southeastern Idaho and in
Utah are alfalfa, barley, corn, animal feed grains, potatoes, and wheat. Wheat, barley, and other grains
are watered typically in late May, June and July, but watering stops in late July or early August to allow
the grains to dry for harvest. Potatoes and corn are watered through the whole summer, in June, July and
August. Alfalfa watering stops twice each season in Idaho to allow the crop to be cut, dried, and
harvested. The dates these happen vary each year, but generally occur in mid- to late-June and in late-
July to early August. Figure 8 below represents the periods of highest load potential using 10 year
historical data from the watering periods of the most common crops in the program. The 2010 and 2011
load data for the Big Grassy substation which primarily serves irrigation load is included to denote the
variability for any given year.

Figure 8. Irrigation Crop Detail
Most of the variability portrayed in the graph is due to weather and the maturation period of the crops.
Alfalfa accounts for around 51% of the crop within the program and watering discontinues twice in
Idaho each season to allow for drying and harvesting. Although average crop and weather patterns
provide a good indicator of what may occur, each individual year may fluctuate drastically.
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Big Grassy Sub '10 (%)
Big Grassy Sub '11 (%)
   2011 Idaho Irrigation Post Report

Field Engineering Page 9 of 19 11/2011

Idaho Weather
Irrigation of Southeastern Idaho crops is necessary because the weather during the summer growing
season is typically warm and dry. The amount of spring precipitation in May and June, effects when
irrigation begins. When there is more precipitation in May and June, irrigation begins later.
June, July and August air temperature and precipitation affect the total summer irrigation electrical load.
Higher air temperatures and lower precipitation lead to higher summer irrigation load, since more
irrigation water will be needed on the crop. Data on precipitation, temperature, and power demand for
June through August of 2011 are shown in Figure 9 below.

Figure 9. June – August 2011: Weather and Power Use
According to monthly climate summary reports by the Pocatello area branch of the National Weather
Service, the summer of 2011 was drier than normal, and August was warmer than normal. Normal
precipitation total for these summer months is 2.22 inches. The observed precipitation total for June,
July, and August 2011 was 1.15 inches—about 50 percent of normal. Temperatures in June 2011 were
0
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June ‐August 2011 Weather and Power Use
2011 Daily Precip., inches
2011 Daily High Temp, 
degrees F
2011 Big Grassy + Jefferson 
Daily Avg. Power (MVA)
   2011 Idaho Irrigation Post Report

Field Engineering Page 10 of 19 11/2011

cooler than normal by about four degrees on average, July 2011 was about normal, and August 2011
was warmer than normal by about three degrees on average. In August 2011 there were seven more
days than normal with the high temperature above 90 degrees.
Idaho Transmission System
Most of Rocky Mountain Power’s southeastern Idaho irrigation customers are served by circuits that
originate at one of the eight major transmission substations in the area. These transmission substations
and the lower voltage distribution substations and circuits function as a system to supply power to about
91% of all irrigation loads in Idaho. The transmission substations, all in the Snake River Plain in
southeastern Idaho, are Amps, Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and
Rigby. These substations delivered 236 megawatts of non-diversified irrigation peak demand to
Irrigation Load Control Program customers in July of 2011, see Figure 10 below.
The curtailment events in this report were not in response to any limitation on these eight substations
since they have adequate transmission capacity to serve all the connected irrigation customers in the
area. Rather, the curtailment events are due to other factors affecting the broader system.  

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Summer Daily Peaks ‐Idaho Transmission
8 SUB TOTAL
Figure 10. Summer Daily Peaks - Idaho Transmission
   2011 Idaho Irrigation Post Report

Field Engineering Page 11 of 19 11/2011

IRRIGATION LOAD CONTROL PROGRAM DETAILS
Irrigation Load Control (Schedules 72 & 72A) is offered to irrigation customers receiving electric
service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service. Participants allow the
curtailment of their electricity usage as prescribed in Schedules 72 and 72A in exchange for a
participation credit. For most participants their irrigation equipment is set up with a dispatchable two-
way control system giving the Company control over their loads. Participants are provided a day-ahead
notification in advance of control events and have the choice to opt-out of a limited number of dispatch
events per season.
Load control events in 2011
The 2011 Irrigation Load Control Program was available for 52 hours from June 1st to August 31st. The
program had the estimated potential to curtail 196 megawatts of load on July 18th, the peak day.
In 2011 Rocky Mountain Power had three load control events. The first load control dispatch was on
June 29, 2011 and was estimated to reduce peak system load by 168 megawatts in Idaho. This
curtailment represented 69% of the potential 2455 megawatts of available load control customer’s peak
demand.
The second dispatch occurred on July 7, 2011 and was estimated to reduce system peak 160 megawatts.
This curtailment represented 62% of the potential 2586 megawatts of available load control customer’s
peak demand.
The third dispatch was on July 11, 2011 and was estimated to reduce the system peak by 165 megawatts.
This curtailment represented 64% of the potential 258 megawatts of available load control customer’s
peak demand.
Idaho load control events for 2011 achieved 62% to 69% of the available participant peak load.

5 Demand fluctuates month to month. June’s undiversified demand for load control customers was 245 megawatts. 6 July’s undiversified demand for load control customers was 258 megawatts.
   2011 Idaho Irrigation Post Report

Field Engineering Page 12 of 19 11/2011

First Event: June 29, 2011
Irrigation Conditions: Wetter than normal conditions. The week had above average
temperatures with Alfalfa watering being down for cutting.
Dispatch Factors:
• High temperatures: Second consecutive day of very high temperatures. Peak load was
expected to be extremely high.
• Generation: The Lakeside plant in Utah was offline for repairs through July 8, 2011.
• Transmission: Capacity on the Point of Rocks-Platte line was de-rated for maintenance
which severely limits the ability to move wind and coal generated power from Wyoming
into Idaho.
Program Performance
Extrapolating data from the largest irrigation load substations* suggests total Idaho program
performance around 168 megawatts on June 29, 2011, providing for an estimated 69% of the
potential 245 megawatts of available load control customer’s peak demand.
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6/29/2011 Curtailment
PROJECTED W/O CURTAIL
SCADA SUBS' LOAD
*Data from the Amps, Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and Rigby
substations. These substations represent approximately 91% of the Idaho Irrigation Load Control
Program participants.
   2011 Idaho Irrigation Post Report

Field Engineering Page 13 of 19 11/2011

Second event: July 7, 2011
Irrigation Conditions: This week was above average in temperature in Idaho. All crops were
in their watering cycle.
Dispatch Factors:
• High temperatures: Second consecutive day of very high temperatures. Peak load was
expected to be extremely high.
• Generation: Huntington 2 offline.
Program Performance
Extrapolating data from the largest irrigation load substations *suggests total Idaho program
performance around 160 megawatts on July 7, 2011, providing for an estimated 62% of the
potential 258 megawatts of available load control customer’s peak demand.
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7/7/2011 Curtailment
PROJECTED W/O CURTAIL
SCADA SUBS' LOAD
*Data from the Amps, Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and Rigby
substations. These substations represent approximately 91% of the Idaho Irrigation Load Control
Pr r m r i i n .
   2011 Idaho Irrigation Post Report

Field Engineering Page 14 of 19 11/2011

Third Event: July 11, 2011
Irrigation Conditions: All crops were in their watering cycle and the area had higher than
average temperatures.
Dispatch Factors:
• High temperatures: Second consecutive day of very high temperatures. Peak load was
expected to be extremely high.
• Generation: Cholla 4 offline with a tube leak.
Program Performance
Extrapolating data from the largest irrigation load substations* suggests total Idaho program
performance around 165 megawatts on July 11, 2011, providing for an estimated 64% of the
potential 258 megawatts of available load control customer’s peak demand.

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7/11/2011 Curtailment
PROJECTED W/O CURTAIL
SCADA SUBS' LOAD

*Data from the Amps, Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and Rigby
substations. These substations represent approximately 91% of the Idaho Irrigation Load Control
   2011 Idaho Irrigation Post Report

Field Engineering Page 15 of 19 11/2011

System Concerns with Irrigation Load Control Program
Voltage Issues System Optimization

Starting in 2008, Rocky Mountain Power noticed voltage issues on circuits and substations with a large
amount of irrigation customers. The following factors were found to contribute to this issue:
• The distribution system in Idaho that serves rural, primarily irrigation areas has capacitors that
are manually engaged at the beginning of each season as irrigation load increases. The
capacitors are disengaged at the end of the season, manually as load decreases.
• Irrigation motor loads create inductive and resistive line losses which reduce system voltage.
These losses are compensated by the capacitors, which raise system voltage to the proper range.
• Irrigation load control events occur while the capacitors are engaged. Each capacitor would
have to be manually disengaged then re-engaged after an event, to keep voltage from rising
above the proper range during the event. This is not reasonable to do manually.
• During an irrigation load control dispatch a high voltage condition is magnified on circuits that
serve predominately irrigation loads with a high percentage of Irrigation Load Control Program
participants. On these circuits when program load is curtailed the voltage goes high and affects
other customers on the circuit. With the instantaneous drop in load, the voltage regulators do not
have time to react to maintain appropriate voltage.
• Due to (1) the popularity of the program, (2) the concentration of loads on agricultural dominant
substations and (3) circuits not having the ability to scale loads, load curtailment events were
inadvertently causing high voltage on some circuits or substations.
To mitigate some of the issues identified, Rocky Mountain Power installed a 3-step capacitor bank on
the 69 kilovolt bus at Big Grassy substation before the 2011 irrigation season. The addition of the
stepped capacitor bank improved voltage regulation on the 69 kilovolt bus at Big Grassy substation but
did not resolve all the other substation and circuit issues, see Figure 11 below. Furthermore, the
irrigation load control program resources in 2010 were dispatched in three or four blocks over 8 to 12
hours. While the dispatch blocks allowed the program to be operationally effective, it negatively
impacted the programs cost-effectiveness.

   2011 Idaho Irrigation Post Report

Field Engineering Page 16 of 19 11/2011

To address the system and cost-effectiveness issues, a settlement was reached in 2011 with the Idaho
Commission staff, the Idaho Irrigation Pumper Association, and Rocky Mountain Power. The settlement
stated that Rocky Mountain Power would invest a minimum of $1.3 million dollars before the 2012
irrigation season to reduce the constraints on the system during high participation in the Irrigation Load
Control Program.
To comply with the settlement agreement Rocky Mountain Power studied the distribution system to
determine which circuits were affected the most by the Irrigation Load Control Program. It was
determined that fourteen circuits on seven substations were most susceptible to high voltage issues
relating to the program. Rocky Mountain Power engineered a solution to the problem by replacing
manual capacitor banks with automatic sensing capacitors that would turn on and off automatically to
maintain acceptable voltage levels. On these 14 circuits, 46 automatic switched capacitors are being
installed and 59 manual capacitors are being removed. This work is scheduled to be completed before
the start of the 2012 irrigation season. In addition to the capacitors, voltage meters will be installed on
the seven substations supplying the 14 circuits. Four additional meters will be placed out on the
distribution circuits to monitor voltages. These meters allow for optimization of the new capacitor
controls and ensure they are working properly.

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Big Grassy Voltage
2009
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2011
Figure 11. Big Grassy Voltage
   2011 Idaho Irrigation Post Report

Field Engineering Page 17 of 19 11/2011

Harmonic Issues 
Rocky Mountain Power has seen a substantial increase in harmonic issues in 2011. The largest
contributors to the harmonic pollution on Rocky Mountain Power’s irrigation feeders are unfiltered
variable frequency drives used to drive large irrigation pumps. Harmonic pollution is unrelated to
Idaho’s irrigation load control program.
Irrigation center-pivot swing arms walked off of their prescribed track, due to harmonic pollution.
Center-pivot swing arms follow buried trace wires to determine which route to follow. The signal on the
trace wires is similar to the 13th, 17th, and 19th harmonics currents produced by unfiltered variable
frequency pump motor drives. The antenna array the center-pivot uses to follow the trace wire was being
influenced by harmonic pollution and failed to follow its intended path. Figure 12 below shows the
typical antenna array that is used to follow the buried trace wires.
Three pivots left their intended path in 2009, one pivot left its intended path in 2010 and eight pivots left
their intended paths in 2011. Five of the troubled pivots in 2011 left their intended path multiple times.
Efforts to mitigate the harmonic pollution issues included several strategies. First, Rocky Mountain
Power provided better feedback and education to irrigators and electrical contractors as to the
importance and application of filtering for their variable frequency drives to insure IEEE 519
compliance. Some of Rocky Mountain Power’s customers have been unwilling to add harmonic filtering
to their variable frequency drives. Rocky Mountain Power will continue to work with these customers to
reduce harmonic pollution levels.
Second, Rocky Mountain Power reviewed susceptibility issues with center-pivot system designers and
manufacturers. Center-pivot manufacturers were unwilling to change their swing arm tracking design
because according to them, the design has worked for the last 30 years with very few problems. Variable
frequency drive motors were not widely used in irrigation systems until recent years. Also,
manufacturers are now promoting GPS tracking swing arms which will likely replace the older
technology in future years, and alleviate this problem.
Figure 12. Typical Center Pivot Antenna Array
   2011 Idaho Irrigation Post Report

Field Engineering Page 18 of 19 11/2011

Last, Rocky Mountain Power must continually monitor the status of line-type capacitor banks.
Capacitors act as higher frequency sinks for higher order harmonics. If one bank is not working
correctly, harmonic pollution levels on the system could affect center-pivot swing arm tracking.

~~ROCKY MOUNTAIN POWER
A <>MSKlH Of " .. ,,,,,,,,,"p
   2011 Idaho Irrigation Post Report

Field Engineering Page 19 of 19 11/2011

CONCLUSIONS
The report analysis leads to these conclusions:
• The Idaho irrigation load represents a significant percentage of Idaho’s peak load, 42%.

• The Irrigation Load Control Program was dispatched three times in 2011 and is estimated to
have curtailed an average of 164 megawatts of the available participant peak demand, 64% of the
available load control customer’s peak demand.

• The distribution system improvements that will be in place before the 2012 irrigation season are
intended to address the known voltage issues. Future distribution circuit and voltage monitoring
will need to continue to make sure the system is operating properly.

• Harmonic pollution on Rocky Mountain Power’s irrigation distribution circuits continues to be a
problem and has caused irrigation pivots to walk out of alignment and contact distribution lines.