20050906Application Part II.pdf

Final
Residential Refrigerator
Recycling Program:
Economic Analysis in
Support of Idaho Tariff Filing
Prepared for:
PacifiCorp
August 16,2005
Prepared by:
Quantec , LLC
K:\2004 Projects\2004-02 (PC) Reg Asst\2004-02R 2005 Idaho Residential Filings\Appliance Recycling\ldaho Refrigerator Tariff
Support 081605.doc
Quantec Offices
6229 SE Milwaukie Ave.
Portland, OR 97202
[phone]
[phone] fax
www.quantecllc.com
1722 14th St., Suite 230
Boulder, CO 80302
[phone]
[phone] fax
28 Main St., Suite A
Reedsburg, WI 53959
[phone]
[phone] fax
1038 E. Bastanchury Rd. #289
Fullerton, CA 92835-2786
[phone]
[phone] fax
Printed on\:tI recycled paper
3445 Grant St.
Eugene, OR 97405
[phone]
[phone] fax
6 Ridgeland Rd
Barrington, RI 02806
[phone]
[phone] fax
20022 Cove Circle
Huntington Beach, CA 92646
[phone]
Contents
Program Description.
...... ...... ...... ........ ...
.......... ..... ....... ........ ... 1-
Eligibility Requirements ........................................................................
Marketing. ......
... ............... ...... ........... ....... ... ....... ... ...... ............. .... ..... .....
Incentives ....
..... ..... ... .... ....... ........ .... ...... ..... ...... ... .... ........... ........ ...... ......
1- 2
Customer Application............................................................................
Program Delivery.... .......................
...... ..... ......
................. ....... .............. 1-
II.Program Budget..
......... ........ .... ............ ..... ...
......... .... ... ...... ..... 11-
III.Cost Effectiveness.........
..... .... ............. ..... .... ........ ....
......... .... 111-
Results ................................................................................................ 111-
IV.Program Evaluation Plan.......................................................IV-
Overview............................................................................................ IV-
Task 1: Data Collection ...................................................................... IV-
Task 2: Estimate Energy Savings Due to Program............................. IV-
Task 3: Assess Cost Effectiveness...................................................... IV-
Task 4: Report Preparation and Presentation (Years 1 , 2) ................. IV-
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
Program Description
The Idaho Residential Refrigerator Recycling Program (the Program) will be
available to Idaho residential customers and operated by a third-party program
administrator. Energy resources will be acquired in the residential market by
providing incentives for customers to discontinue use of their second
refrigerator and/or upgrade their old primary refrigerators and freezers to new
energy-efficient models. The discarded appliances will all be taken out of use
permanently and recycled to avoid being resold on the secondary market. The
Program administrator is experienced in recycling refrigerators and is able to
recycle 92% of appliance parts while complying with U.S. Environmental
Protection Agency (EP A) guidelines.
Approximately 15% of Utah Power residential energy use is attributed to
refrigeration. A significant portion is from second refrigerators and freezers.
Utah Power s Energy Decision 2001 survey indicates that 14% of residential
customers own a second refrigerator and 72% own stand alone freezers in
Idaho. It is estimated that more than 2 600 inefficient appliances will be
removed from use through this offering. Annual kWh savings is estimated to
be 1029 kWhl per unit or 2 721 MWh in total at the end of the two-year
program. Peak reduction is estimated to be 0.5 MW. Total costs over the two-
year Program are estimated to be $516 775.
In addition, the Program will provide a leave-behind packet, one per
household. The packet will contain written energy efficiency education
materials and instant savings measures for a net annual savings of 64 kWh per
packet. Annual savings at the end of the two year program from these
measures is estimated to be 152 MWh.
Eligibility Requirements
The Program is open to all residential customers of Utah Power in the state of
Idaho served on rate Schedule 1.
Marketing
A mass-market campaign will launch the offer through the Program
administrator with oversight by PacifiCorp s External Communications and
Customer Support Services staff. Once commission approval is obtained, the
Program will be implemented and will remain in place over a two-year period.
Source: "Evaluation of the Utah Refrigerator and Freezer Recycling Program , Quantec,
LLC August 3, 2004
Ibid.
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
The marketing plan will be timed to coincide with the warmest months of the
year during which energy efficiency is at the forefront of people s minds. Past
experience indicates that the period between Thanksgiving and the end of
January have the lowest interest and participation. Consequently, newspaper
advertising will focus on the remaining nine months of the year. The
combination of newspaper and television advertising will reach 95% of the
target market an average of 29 times over each nine-month campaign.
Promotion Plan
Press Releases
. B ill Inserts
Newspaper ads
Program launch event
Clipping service
Incentives
A $40 incentive will be provided to residential customers for a maximum of
two working refrigerators and/or freezers. In addition, participants will receive
an energy efficiency packet consisting of an ENERGY ST AR (ID -certified
compact fluorescent light bulb, refrigerator/freezer thermometer, and energy
education materials.
Table 1.1 summarizes the program characteristics.
Table 1.1: Program Characteristics
Refrigerator Recycling
Energy Efficiency Packet 380 029 $40
Customer Application
Customers may sign up for the Program through either a toll-free number or a
Web site.
Program Delivery
The Program administrator will schedule pick-ups by geographic area to
minimize costs. Refrigerators will be picked up and delivered to a central
recycling center.
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
Program Budget
The Residential Refrigerator Recycling Program has a projected two-year
budget of $516 775. The Program budget by category is summarized in
Table 11.1 below.
Table 11.1: Annual Utility Costs and Savings
$156,050
$156 050
$312 100
$12 000
$12 000
$24 000
$10 000
$10 000
$20,000
$20 000
$20,000
$40,000
$60,337
$60,338
$120,675
$258,387
$258,388
$516 775
1,436,735
1,436 735
873,470
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
11-
Cost Effectiveness
Table Ill.l provides the additional assumptions used in the analysis of cost
effectiveness. The discount rates were obtained from two sources. For the
TRC, the discount rate used is the US Treasury Long-Term Composite bond
rate posted on August 16, 2005. PacifiCorp s cost of capital as reported in the
2004 Integrated Resource Plan served as the discount rate for the other tests
(Utility Cost Test, Ratepayers Impact Measure, and Participant). PacifiCorp
also provided the values for line losses and the residential retail energy rate.
Table 111.1: Program Inputs
1!~ill~II~II~~~II~IIIIII~II~IIJI~lllilllllllllllliII111'111111111111111111111111111111111111111111111111111111Ilillllllll 1111 1111111111; 1;111111111111111111111111,11'1111111111111111111111III
Discount Rate for TRC test 4.45%
Discount Rate for UCT, URIM, PART tests 176%
Line Loss 10.23%
2004 Average Residential Retail Rate ($/kWh)0404
Results
The cost effectiveness of the Program was calculated using Quantec' s
Demand Impact and Cost Effectiveness (DICE) model. The model distributes
the estimated annual kWh savings across the year based on an hourly
residential refrigerator load shape. Each of these hourly savings values is
multiplied by the associated hourly-avoided costs from PacifiCorp s market
price forecasts. These products are all discounted back to the present. This
approach accurately captures the hourly differences in the value of a kWh
during the year. Quantec analyzed two avoided cost scenarios.
The base scenario was calculated based on PacifiCorp s official market price
forecasts base case for Palo-Verde Hub, dated June 30, 2005.
The IRP case uses annual system value estimates based on the August 2005
update of PacifiCorp s 2004 IRP 65% load factor decrement. The total costs
of the IRP model after the load has been decremented are subtracted from the
base IRP model costs. This difference is the value specific to PacifiCorp
system from these savings.
The Program passes the TRC, and Utility Cost Tests in both the base market
price and the IRP scenario. The Program fails the Rate Impact Test, indicating
that the Program will increase average rates slightly. The Participant cost-
benefit ratio was not calculated, as participants face no costs in this Program.
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
111-
Table 111.2: Cost-Effectiveness Results: August 2005 Updated 2004 IRP
65 % Load Factor Decrement Scenario
Total Resource Cost Test $0.0155 $357 206 013 376 $656,170 837
(PTRC) + Conservation Adder
Total Resource Cost Test (TRC)$0.0155 $357 206 $921 251 $564 045 579
No Adder
Utility Cost Test (UCT)$0.0203 $466,033 $810,481 $344,448 739
Rate Impact Test (RIM)163,716 $810,481 $353 235 696
Participant Cost Test (PCT)($108 827)$811 904 $920,730 n/a
Lifecycle Revenue Impacts ($/kWh $0.0000114945
Table 111.3: Cost-Effectiveness Results: June 30, 2005 Base Market Price
Scenario
Total Resource Cost Test $0.0155 $357 206 312 277 $955 071 674
(PTRC) + Conservation Adder
Total Resource Cost Test (TRC)$0.0155 $357 206 192 979 $835 773 340
No Adder
Utility Cost Test (UCT)$0.0203 $466,033 057,414 $591 381 269
Rate Impact Test (RIM)163 716 057,414 $106 302 909
Participant Cost Test (PCT)($108 827)$811 904 $920,730 n/a
Lifecycle Revenue Impacts ($/kWh $0.0000034591
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
111-
IV. Program Evaluation Plan
The following sections describe the Program s impact evaluation plan.
Overview
The objective of this evaluation is to develop an estimate of the energy and
demand savings due to this Program and its cost effectiveness. A key
component in this analysis is the energy consumption of the replaced
refrigerators and freezers, or the full-year unit energy consumption (UEC).
Secondary data sources are available for estimating the UEC of replaced units.
Because some refrigerator/freezer replacements may have occurred in the
absence of this Program, we will include an assessment of the net-to-gross
(NTG) ratio.
Task 1: Data Collection
Several refrigerator studies have been carried out in various parts of the
country. These reports present a wide array of information. The first step in
this task will be to identify relevant reports, review the data and analysis
approaches, and document the findings.
Two primary data collection activities will be carried out including:
1. Unit energy consumption estimation
2. Customer surveys.
Energy Consumption Measurements
A study of energy use for replaced refrigerators and freezers was conducted in
support of a similar program sponsored by Southern California Edison
(Refrigerator/Freezer UEC Estimation, 1996 ARCA/SCE Turn-In Program: In
Support of XENERGY Inc. Evaluation of the 1996 Appliance Recycling
Program by John Peterson of Athens Research). This report and Quantec
August 3, 2004, report "Evaluation of the Utah Refrigerator and Freezer
Recycling Program " will be used to corroborate the energy savings reported
in this Program.
The Program implementer will provide the following information for each
unit recycled:
Customer name and address
Appliance manufacturer, model number, year, serial number and size
.QUante. C
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
IV-
For a minimum of 120 refrigerators and 120 freezers recycled through the
Program, the implementer will also provide energy usage information as
reported by the Association of Home Appliance Manufacturers (AHAM) for
each unit. Degradation curves will be used to estimate the usage based on the
age of the unit.
Participant Survey
A survey of participating customers will be undertaken to provide data needed
to assess the NTG ratio for the Program and customer satisfaction levels.
Table 1 shows the data categories and elements that need to be obtained
through the survey. The following describe the data needs:
1. Customer Information. These data will be acquired to characterize the
participants and allow for extrapolation of the results to the entire
Program population.
2. Participants ' Perceptions and Satisfaction. These questions will
provide information about how the participant became aware of the
Program, their satisfaction with its various components and the utility
overall, and suggestions for improving Program delivery.
3. Free Riders. Participants will be asked questions about what they
would have been most likely to do with their appliance(s) if they had
not participated in the Program and when they would have taken
action. The key data from this set of questions will be the proportion of
customers who would have permanently removed their old
appliance(s) from service, whether the customer has recently
purchased a new refrigerator/freezer, how many refrigerators/freezers
are in the home and the location of the removed refrigerator/freezer. A
series of questions will be needed to clarify the specific actions that
would have been taken and improve upon the validity of the responses.
4. Unit Replacement. Participants will be asked whether they have or
plan to replace the recycled unit and, if so, the manufacturer and model
number of the replacement unit.
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
IV-
Table IV.l: Participant Survey Data Collection
Customer Information Name Address
Household size Annual income
Head of household age Home type
Program Perceptions How did customer become aware of Program?
and Satisfaction How satisfied is customer with Program delivery
schedule, communications, implementer performance,
incentive, overall?
What improvements would customer recommend?
How satisfied is customer with Utah Power overall?
Free-Riders/What would customer have done with existing
Unit Replacement refrigerator/freezer without the Program?
When would customer have taken action?
How often would refrigerator/freezer have been operated if
it had been kept?
Was the recycled unit replaced and if so the manufacturer
and model of the replacement unit.
To ensure that results can be estimated to provide a 90% confidence and 10%
precision level, two participant surveys (with sample sizes of 100 each) will
be conducted - one each year of the Program.
Task 2: Estimate Energy Savings Due to Program
Program energy and demand impacts will be estimated using data collected in
Task
In cases where participants recycled an existing appliance but replaced it with
a new unit, the savings will be calculated using an average energy
consumption value for new units based on refrigerator and freezer energy
guide label values. For the proportion of participants who recycled a unit
through the Program and did not replace it, gross savings will be the
consumption of the recycled unit.
Task 3: Assess Cost Effectiveness
The cost effectiveness of the Program will be calculated using the estimated
savings from Task 2. Demand impacts will be calculated taking into account
the average demand estimated for refrigerators and freezers from the energy
savings of recycled units.
Because of the uncertainties associated with what participants would have
done without the Program, it will be desirable to examine alternative
assumptions that affect the NTG calculation and ca ;ulate a range of savings.
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
IV-
Prior studies will be used to define reasonable assumptions that merit
examination.
The value of energy and demand savings will then be estimated by
multiplying the savings by the hourly-avoided costs from PacifiCorp' s market
price forecasts. The product will then be discounted back to the present. From
this and the Program cost data, Total Resource Cost test, Utility Cost test
Ratepayer Impact Measure test, and Participant Cost tests will be derived.
Task 4: Report Preparation and Presentation (Years
Quantec will prepare a draft and final report that will summarize the findings
of this evaluation at the end of first Program year and at the end of Program.
The reports will include the following sections:
Executive Summary
Methodology
Background or Introduction
Process Information
Impact Evaluation Recommendations
Appendices (including a bibliography and reference list, clean copies
of interview guides and survey instruments, and documentation of any
electronic databases)
The evaluation team will provide a draft report to PacifiCorp and will
incorporate all comments into the final report.
.QUOnte C
Residential Appliance Recycling Program
Economic Analysis in Support of Idaho Tariff Filing
IV-
Final
Idaho Low Income
Weatherization Program:
Analysis
Support of Tariff Revision
Prepared for:
PacifiCorp
August 2005
Quantec OffiCf"it
6229 SE Milwaukie Ave.
Portland, OR 97202
[phone]
[phone] fax
www.quantecllc.com
3445 Grant St.
Eugene, OR 97405
[phone]
[phone] fax
1722 14th St., Suite 230
Boulder, CO 80302
[phone]
[phone] fax
6 Ridgeland Rd
Barrington, RI 02806
[phone]
[phone] fax
Prepared by:
Brian Hedman
M. Sami Khawaja , Ph.
Quantec, LLC
212 E Main St., Suite G
Reedsburg, WI 53959
[phone]
[phone] fax
20022 Cove Circle
Huntington Beach, CA 92646
[phone]
Printed \:tI rOC/clad paper
Table of Contents
Program Description
.. ........... ........ .........
................... ....... 1-
Other Program Costs..............................................................................1- 7
II.
III.
Cost Effectiveness........................................................... 11-
Eval uation Plan............................................................... 111-
Impact Evaluation............................................................................... 111-
Management & Reporting .................................................................. 111-
Timeline.............................................................................................. III - 3
Appendix A. EP A Guidelines..................................................
Safe Disposal Requirements.................................................................
Section 608 of the Clean Air Act of 1990 ............................................
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Program Description
The current Low Income Weatherization Program has been in place for over
ten years. It is available to Utah Power customers with incomes at or below
150% of federal poverty guidelines that have installed electric heating
systems. Services are provided at no cost to participants because partnering
agencies are able to leverage Utah Power funding with federal and state funds
they receive. Utah Power offers rebates directly to the Eastern Idaho Special
Services Agency and the SouthEastern Idaho Community Action Agency
Agencies ) that administer the Program. The average annual number of
completions during the period 2000 through 2004 is 23.
Utah Power in consultation with their two partnering non-profit agencies is
proposing revisions to the current program (Schedule 21). There are four
goals to this effort.
1. To increase Utah Power customer participation numbers.
2. To provide incentives for the installation of additional cost effective
measures.
3. To offer rebates on measures that reduce electricity consumption in
homes regardless of heating source.
4. To reimburse agencies for services up to two times per home, one
time per measure. This allows the installation of new technologies
and/or measures that previously were not considered cost effective.
The agencies provided expected participation rates for the revised program
based on their historic weatherization program experience. Estimates are
presented in Table 1.1.
Table 1.1: Expected Annual Participation Rates
Electric Base Load Program Participants
Electrically Heated Homes
170
Proposed Rebates: The following summarizes Utah Power s proposed
reimbursement available to the Agencies for the installation of approved
measures and reimbursement on administrative costs:
A rebate averaging up to $1 500 per home annually (April 1 through March
31) will be provided towards the cost of installed qualifying Major and
Supplemental Measures. The following measure: ' ltegories will be eligible for
rebates:
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Weatherization Measures in Electrically Heated Homes
Compact Fluorescent Light Bulbs (CFLs)
Refrigerator Replacements
Water Saving Measures in Homes with Electric Hot Water Heaters
Weatherization
Major Measures with a Savings to Investment Ratio (SIR) of 1.0 or greater are
required (based on results of the State of Idaho Weatherization Energy
Analysis) on homes with an electric heating system that is operable and
permanently installed with the capacity to heat at least 51 % of the dwelling. If
physical barriers exist that prohibit the installation of a measure, the measure
is not required. A list of qualifying measures follows. Greater R-values than
listed below may be installed as long as audit results show it to be cost
effective:
Insulation up to R-48 for ceilings with less than R-30 in place.
Floor insulation over unconditioned spaces up to R-
Insulation (not urea-formaldehyde) up to R-26 for walls without insulation
installed
Class 40 replacement windows
Supplemental Measures qualify for a rebate when they are determined to be
cost effective.
Funding is available on the following Supplemental Measures installed in
electrically heated homes:
Attic ventilation when installed with ceiling insulation
Ground cover and water pipe insulation when installed with floor
insulation
Forced air electric space heating duct testing, insulation, and sealing in
unconditioned spaces
Weather stripping and/or caulking including blower door assisted air
sealing and duct sealing
Thermal doors
Timed thermostats on centrally controlled multi-room heating/cooling
systems
Funding is available on the following supplemental measures installed in all
homes:
Compact fluorescent light bulbs -limit 6 Energy Star certified bulbs per
home placed in fixtures that are on 2 hours or more per day.
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Refrigerators identified in the Weatherization Assistance Program
Technical Assistance Center (W APT AC) database as having mean annual
usage of 900 kWh or greater may be replaced with an Energy Star model
with estimated annual consumption of 500 kWh or less. Replaced
refrigerators must be removed and recycled in accordance with EP
guidelines.
Pipe insulation, energy-efficient showerheads, and aerators for homes with
an electric water heater.
Administrative Cost Reimbursement will be provided at 15% of Utah Power
reimbursement for Major and Supplemental Measures with a minimum of
$150 on homes with at least one major measure installed and $50 on homes
without the installation of a major measure, not to exceed the following per
building (Table 1.2).
Table 1.2: Program Administration
Minimum Payment - $150
w/major measure, $50 without
major measure
1 to 4
5 to 10
11 to 15
16 to 20
21 to 25
26 to 30
31+
$350
$800
200
$1,400
600
800
100
Table 1.3 displays the assumptions used in the Program design and in
conducting cost-effectiveness analysis. The U.S. DOE estimates the average
cost per home throughout the nation is $2 744 (based on the 2005 DOE
Weatherization Guideline). The average total cost of homes completed
through the Utah Power program in 2004 was $1 678. Expected savings are
based on an Oakridge National Laboratory study of weatherization programs.
These savings include the Major Measures and Supplemental Measures with
the exception of CFLs, and refrigerator replacements, which are separately
estimated below. We used a 30-year economic life for the weatherization
component of the Program. Overall weatherization measures were assumed to
have a 30- year economic life.
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Table 1.3: Weatherization Assumptions
Number of Homes Annually Agencies Total Annual Savings (kWh)150 710
Total Utah Power Annual Contribution $15,750
National Average Total Cost S. DOE 744 to Admin Cost
~verage Total Savings (kWh) *ORNL /CON-488 153 Total Utah Power Annual Rebate $105,000
02/2003
~verage Admin Cost Utah Power $225 Total Annual Utah Power Cost $120,750
~verage Rebate per Home Utah Power 500 Total Annual Cost $192 080
* Includes Major Measures and Supplemental Measures except as noted below.
Compact Fluorescent Light Bulbs (CFL)
Utah Power will pay 50% of the bulb cost for up to eight ENERGY STAR(B)
certified CFLs per home, to be placed in lighting fixtures that are in use for
two or more hours/day. Table 1.4 displays the assumptions used in the CFL
portion of the Program and in conducting cost-effectiveness analysis.
Estimates of CFL cost were derived from several other recent programs. The
average wattage of replaced bulbs, installed bulb wattage, and expected
number of hours of use were derived from PacifiCorp s evaluation of its CFL
program in Utah. The total number of CFLs to be installed is determined by
multiplying the expected participation level from Table 1.1 (170 households)
by eight. The program requirements will limit installations of CFLs to
locations with at least two hours of use per day. With a minimum of two hours
per day, we assumed an overall average use time of three hours per day across
the installed CFLs. Average energy savings as a result of CFL replacement is
calculated as the difference in wattage between the average incandescent light
bulb (70 Watts) and the replacement CFL (20 Watts), multiplied by hours of
use per day (3 hours) and days per year (365). This product is then converted
to kWh by dividing by 1 000. The economic life of a CFL light bulb (9 years)
is determined by assuming 10 000 hours of bum time divided by the annual
hours of use (10,000/(3*365)). Agency administrative payments are limited to
15% of the Utah Power estimated contribution of $1 700.
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Table 1.4: CFL Assumptions
No. CFLs per Home Program Total Annual No. CFLs 360
Average Cost per CFL Various $2.Avg. CFL Savings (kWh)54.
Average Existing Wattage Utah Eva!.Total Annual Savings (kWh)74,460
Average New Wattage Utah Eval Total Utah Power Annual $255
Contribution to Admin Cost
Total Utah Power Rebate 700
Average No Hours per Day Utah Eva!.Total Annual Utah Power Cost $1,955
Total Annual Program Cost 655
Rebate as % of CFL Cost Utah Power 50%Economic Life (Years)
Refrigerato rs
Refrigerators can be replaced where existing models are listed in the
W APT A C database as having annual mean usage of 900 kWh or greater.
Replacement refrigerators will be ENERGY STAR-certified models with
annual consumption levels of 500 kWh or less. Replaced refrigerators will be
removed and recycled according to Environmental Protection Agency (EP
guidelines.
Table 1.5 displays the assumptions used in the refrigerator replacement portion
of the Program and in conducting cost-effectiveness analysis. The
consumption data are based on metered units from a similar program run in
Utah during 2003. We assumed a 19-year economic life for a new refrigerator.
Utah Power s total annual cost is set at 50% of the cost of replaced
refrigerators. As mentioned above, the administration fee is limited to 15% of
Utah Power contribution.
Existing refrigerators consuming nver 900 kWh annually can be cost-effectively
replaced. For detailed information concerning EP A Guidelines, please refer to Appendix
Low-Income Weatherization Program
Analysis in Support of Tariff Filing
1-5
08/22/05
Table 1.5: Refrigerators Assumption
Number of Refrigerators Tested Agencies 153 No. Refrigerators Replaced
Proportion of Tested Replaced Utah Pgm 44% Avg Annual Savings (kWh)510
vg Cost per New Unit Agencies $600 Total Annual Savings (kWh)101 653
vg Cost Per Tested Unit Agencies Total Annual Equip Cost $40,800
vg Consumption of Existing Unit (kWh)Utah Pgm 944 Total Annual Testing Cost
vg Consumption of New Unit (kWh)Utah Pgm 434 Total Utah Power Contribution $3,060
0 Admin Cost
Rebate as % of Unit Cost Utah Power 50%otal Utah Power Rebate $20,400
Economic Life (Years)19 Total Annual Utah Power Cost $23,460
Total Annual Cost $43 860
* The WAPTAC database will be used in lieu of testing2
Hot Water Measures
Table 1.6 displays the assumptions used in the design of the hot water portion
of the Program, and in conducting cost-effectiveness analysis. The segment of
clients likely to have gas heat with electric hot water was estimated at 10%
(approximately 17 households). The program will install low-flow
showerheads, kitchen and bathroom aerators and pipe wraps for these
customers. Energy savings estimates were obtained from the evaluation of the
2002 California Low Income Energy Efficiency program . As in the
components above, Utah Power s contribution to administration cost will be
limited to 15% of the total rebate amount for measures installed.
Table 1.6: Hot Water Measure Assumptions
Percent of Participants with gas heat and Agencies 10%Annual Participants
~Iectric hot water
Showerhead savings (kWh)2002 CA LlEE 230 Total Annual Savings (kWh)749
~erators (kWh)2002 CA LI Total Annual Utah Power $97
Contribution to Admin Cost
Pipe Wrap 2004 CA DEER Total Annual Utah Power $323
Rebate
Measure Cost Iowa LI Pgm $38 Total Annual Utah Power Cost $420
Rebate as % of Unit Cost Utah Power 50%Total Annual Program Cost $ 743
Economic Life (Years)
2 Energy use data for over 41 000 refrigerators, refrigerator-freezers, and freezers has been
compiled by D&R International, Ltd., for DOE from the Directory of Certified
Refrigerators, Freezers, and Refrigerator Freezers published by the California Energy
Commission (CEC) from 1979 to 1992. See http://www.waptac.org/sp.asp?id=70
Impact Evaluation of the 2002 California Low Income Energy Efficiency Program, West
Hill Energy and Computing, Inc. October 11, 2004
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Other Program Costs
Table 1.7 displays the estimated Utah Power program management and
administrative costs as well as the estimated cost of a third party evaluator.
Table 1.8 summarizes overall expected annual Program costs and savings.
Table 1.7: Other Program Costs
Utah Power Labor
Evaluation
$10 000
$10 000
*Includes program management, rebate processing and inspections.
** Evaluation costs are estimated to be $20 000, with evaluations occurring every two years.
Table 1.8: Combined Annual Program Costs and Savings
Weatherization
CFLs
Refrigerators
Hot Water
Other
Total
$120,750
955
$23,460
$420
$20 000
$166,585
$192 080
$3,655
$43,860
$743
$20 000
$260,338
150 710
74,460
102 680
749
334 599
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Cost Effectiveness
Cost-effectiveness tests were run for the Program as designed using the
following Standard tests:
Total Resource Cost (TRC): This test examines the program benefits and
costs from the Company and its customers' combined perspective. On the
benefit side, it includes reduction in supply costs. On the cost side, it
includes costs incurred by both Utah Power and the other funders. We also
include a TRC test that includes a 10% conservation adder (PTRC).
Utah Power (Utility Cost Test; UCT): From the Company s perspective
the benefits are in the form of avoided supply and line-loss costs. The
costs include administration, evaluation, and rebate costs associated with
the program.
Ratepayers: All ratepayers (participants and non-participants) may
experience an increase in rates to recover lost revenue. This test (entitled
Ratepayer Impact Measure, RIM) includes all the Company s program
costs as well as first-year lost revenues. On the benefits side, it includes all
avoided energy and capacity costs.
The participant test is included but no benefit cost ratio is calculated due to
zero participant costs. Cost-effectiveness assumptions are summarized in
Table 11.1.
Table 11.1: Program Cost-Effectiveness Assumptions
Energy Savings
Retail Rate
Discount Rate
Line Loss
Measure Life
Avoided Costs
Measure Cost
Incentive Amount
Results
Savings by measure
Average 2004 Residential Retail Rate
The US Treasury Long Term Composite bond rate of 4.60% posted on August 10,
2005 was used for the TRC. Utah Power s estimated cost of capital of 7.18% was
used for the other tests.
10.23% from the 2004 Utah Power line loss study
Each measure has its own expected life.
Primary source is the 2005 Integrated Resource Plan 65% load factor decrement.
We also used the June 31, 2005, official Company forward price curve as a
secondary data source.
Each measure has its own expected cost.
Varies by element. See previous sections.
The cost effectiveness of the Idaho Low Income Weatherization Program was
calculated using Quantec s DeL_and Impact and Cost Effectiveness (DICE)
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Evaluation Plan
The goals of the evaluation are to:
1. Estimate actual energy (kWh) and demand (kW) savings2. Analyze Program cost effectiveness
The Company has committed to a process and impact evaluation at the end of
the second program year.
Impact Evaluation
The impact evaluation will include collecting key data, selecting a random
sample of participants, estimating energy savings, and assessing cost
effectiveness. The impact evaluation approach will vary by type of measure
installed.
Weatherization/Shell
This is not expected to be a large part of the Program. Energy impacts will be
assessed through billing analysis, and demand impacts will be assessed using
residential load shapes from secondary sources.
Compact Fluorescent Light bulbs
The analysis will begin with the Program database for the number of CFLs
installed, initial and final wattage, and hours of use whenever available.
Program database will be used to verify number of CFLs installed, hours of
use, whether the replaced bulbs were in working condition, and number of
bulbs removed. It is recommended that this effort be enhanced with a survey
of about 100 participants to verify the information in the program database.
However, this may also lead to increasing overhead costs to prohibitive levels
given the size of this program.
The data collected will be used to estimate the energy (kWh) savings. The
evaluator will then use secondary lighting hourly use data to estimate the
Program demand (kW) impacts. Actual savings will be verified with billing
analysis as described below.
Refrigerators
The evaluator will utilize the metered data collected from the replaced
refrigerators for estimating the energy and demand impacts. If conducted
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customer surveys will be used to verify the presence of new refrigerators.
Actual savings will be verified with billing analysis as described below.
Savings Analysis
Traditionally, "quasi experimental" research design is the most appropriate
method for conducting impact evaluations of demand-side management
programs. The approach consists of comparing the change in pre- to post-
program energy consumption between the participants and a "comparison
group of customers who, though eligible, did not participate. By accounting
for non-pro gram-related factors that can affect energy use from the pre- to the
post-program periods, the approach can provide estimates of "net" program
impacts.
Census Billing Analysis. A billing analysis will be conducted on all
participants that pass the screen for sufficient billing history. These data will
be compared to a group of low-income customers that did not participate in
the Program.
Princeton Scorekeeping Method5 (PRISM), an established weather-
normalizing tool, will be used to calculate each individual customer s annual
energy consumption under average weather conditions. Utilizing historical
weather data and billing records, PRISM adjusts for the impact of weather
variations upon usage during both the pre and post periods. The result is
weather-normalized and annualized data that allow for the meaningful
interpretation of the true impact of the Program upon energy consumption.
The evaluator will use difference-of-means tests to analyze disparities
between the participants and non-participant billing data.
The evaluator will also analyze the differences between pre and post PRISM-
produced set temperatures for assessment of take back.
Savings by Agency and Measure Type. Utilizing the estimates from the
billing analysis and detailed statistical models, the evaluator will stratify
savings by agency and measure. This will provide valuable insight into the
Program s operation and overall economic performance. This analysis will
provide descriptive statistics on the frequency of installations for specific
measures and groups of interrelated measures. It will also provide estimates of
savings for groups of measures and can be compared to deemed savings to
assess possible discrepancies. Additionally, these data will be stratified by
In order to produce the most accurate results, PRISM models each participant's pre and
post periods separately, generating an individual normalized consumption record for each
period. Employing several stages, PRISM utilizes an iterative process to determine the
appropriate ~~odel (Heating-Only or Heating & Cooling) that best fits the data : 'sed on
the usage characteristics exhibited by the participant.
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agency to provide additional insight into best practices and areas of
improvement.
Quantify Non-Energy Benefits. If surveys are conducted, the evaluator will
estimate non-energy benefits, where applicable.
Conduct Cost-Effectiveness Analysis
The evaluator will conduct a cost-effectiveness analysis using traditional
tools. The analysis will include the standard perspectives (i., utility,
ratepayers, participants, and society) and, as much as possible, non-energy and
environmental impacts (e., carbon dioxide reduction and reduction in forced
mobility). The benefits to Utah Power include the reduction in energy
consumption and the Company s avoided costs.
Program costs include administration, delivery, and actual payments made to
participants. Benefit/cost ratios will be computed from the various
perspectives.
Management & Reporti
The evaluator will deliver a draft and final report of findings. The final report
will reflect all the comments made by stakeholders. It will provide a complete
description of the relevant evaluation objectives and how they were achieved.
The final report is to contain the following elements:
Executive Summary
Description of the Program, its goals, and objectives
Statement of the evaluation goals and objectives
Discussion of methodologies
Implementation procedures and assumptions for each method
Data-collection procedures and methods
Sample design and sample attrition
Results and their interpretation (demonstrated clearly with charts and
tables)
Timeline
A process evaluation of the Program should be conducted approximately one
year after Program implementation to assure that the Program is operating as
planned. An impact evaluation should be conducted two years after Program
implementation to allow sufficient post-implementation billing data to be
availatl~.
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Appendix A. EPA Guidelines
Safe Disposal Requirements
Under Environmental Protection Agency (EPA) rules, equipment that is
typically dismantled on site before disposal (e., retail food refrigeration
central residential air conditioning, chillers, and industrial process
refrigeration) has to have the refrigerant recovered in accordance with EP A'
requirements for servicing. However, equipment that typically enters the
waste stream with the charge intact (e., motor vehicle air conditioners,
household refrigerators and freezers, and room air conditioners) is subject to
special safe disposal requirements.
Under these requirements, the final person in the disposal chain (e., a scrap
metal recycler or landfill owner) is responsible for ensuring that refrigerant is
recovered from equipment before the final disposal of the equipment.
However, persons "upstream" can remove the refrigerant and provide
documentation of its removal to the final person if this is more cost effective.
If the final person in the disposal chain (e., a scrap metal recycler or landfill
owner) accepts appliances that no longer hold a refrigerant charge, that person
is responsible for maintaining a signed statement from whom the appliance is
being accepted. The signed statement must include the name and address of
the person who recovered the refrigerant, the date that the refrigerant was
recovered, or a copy of a contract stating that the refrigerant will be removed
prior to delivery. EP A does not mandate a sticker as a form of verification that
the refrigerant has been removed prior to disposal of the appliance. Such
stickers do not relieve the final disposer of their responsibility to recover any
remaining refrigerant in the appliance, unless the sticker contains a signed
statement that includes the name and address of the person who recovered the
refrigerant and the date on which was recovered.
The equipment used to recover refrigerant from appliances prior to their final
disposal must meet the same performance standards as equipment used prior
to servicing, but it does not need to be tested by a laboratory. This means that
self-built equipment is allowed as long as it meets the performance
requirements. For MV ACs and MV AC-like appliances, the performance
requirement is 102 mm of mercury vacuum; for small appliances, the recovery
equipment performance requirements are 90% efficiency when the appliance
compressor is operational and 80% efficiency when the appliance compressor
is not operational.
Technician certification is not required for individuals removing refrigerant
from appliances in the waste stream.
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
Section 608 of the Clean Ai r Act of 1990
SEC. 608. NATIONAL RECYCLING AND EMISSION REDUCTION
PROGRAM.
(a) In General -
(1) The Administrator shall, by not later than January 1 , 1992, promulgate
regulations establishing standards and requirements regarding the use
and disposal of class I substances during the service, repair, or disposal
of appliances and industrial process refrigeration. Such standards and
requirements shall become effective not later than July 1 , 1992.
(2) The Administrator shall, within 4 years after the enactment of the
Clean Air Act Amendments of 1990, promulgate regulations
establishing standards and requirements regarding use and disposal of
class I and II substances not covered by paragraph (1), including the
use and disposal of class II substances during service, repair, or
disposal of appliances and industrial process refrigeration. Such
standards and requirements shall become effective not later than 12
months after promulgation of the regulations.
(3) The regulations under this subsection shall include requirements that-
(A) reduce the use and emission of such substances to the lowest
achievable level, and
(B) maximize the recapture and recycling of such substances.
Such regulations may include requirements to use alternative substances
(including substances which are not class I or class II substances) or to
minimize use of class I or class II substances, or to promote the use of safe
alternatives pursuant to section 612 or any combination of the foregoing.
(b) Safe Disposal.- The regulations under subsection (a) shall establish
standards and requirements for the safe disposal of class I and II substances.
Such regulations shall include each of the following-
(1) Requirements that class I or class II substances contained in bulk in
appliances, machines or other goods shall be removed from each such
appliance, machine or other good prior to the disposal of such items or
their delivery for recycling.
(2) Requirements that any appliance, machine or other good containing a
class I or class II substance in bulk shall not be manufactured, sold, or
distributed in interstate commerce or offered for sale or distribution in
interstate commerce unless it is equipped with a servicing aperture or
rn equally effective design feature which will facilitate ~'1e recapture
of such substance during service and repair or disposal of such item.
Low-Income Weatherization Program
Analysis in Support of Tariff Filing 08/22/05
(3) Requirements that any product in which a class lor class II substance
is incorporated so as to constitute an inherent element of such product
shall be disposed of in manner that reduces, to the maximum extent
practicable, the release of such substance into the environment. If the
Administrator determines that the application of this paragraph to any
product would result in producing only insignificant environmental
benefits, the Administrator shall include in such regulations an
exception for such product.
(c) Prohibitions. -
(1) Effective July 1, 1992, it shall be unlawful for any person, in the
course of maintaining, servicing, repairing, or disposing of an
appliance or industrial process refrigeration, to knowingly vent or
otherwise knowingly release or dispose of any class lor class II
substance used as a refrigerant in such appliance (or industrial process
refrigeration) in a manner which permits such substance to enter the
environment. De minimis releases associated with good faith attempts
to recapture and recycle or safely dispose of any such substance shall
not be subject to the prohibition set forth in the preceding sentence.
(2) Effective 5 years after the enactment of the Clean Air Act
Amendments of 1990, paragraph (1) shall also apply to the venting,
release, or disposal of any substitute substance for a class I or class II
substance by any person maintaining, servicing, repairing, or disposing
of an appliance or industrial process refrigeration which contains and
uses as a refrigerant any such substance, unless the Administrator
determines that venting, releasing, or disposing of such substance does
not pose a threat to the environment. For purposes of this paragraph
the term "appliance" includes any device which contains and uses as a
refrigerant a substitute substance and which is used for household or
commercial purposes , including any air conditioner, refrigerator
chiller, or freezer.
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ATTACHMENT 5
(Market characterizations for the FinAnswer Express, Energy FinAnswer and Irrigation Efficiency
programs. )
Submitted To:
ACIFICORP
Fi nAnswe~ Express
Market Potential
Assessment
for
PacifiCorp s Idaho
Service Territory
Submitted By:
Nexanr
September 17, 2004
(Updated August 22, 2005)
Contents
Section Page
EXECUTIVE SUMMA R Y ................ ........... .......... ........................ ....... ..........
.............. ................. .............. .............
SECTION 1 INTR 0 D U CTI 0 N .......................................................................................................................
SECTION 2 MARKET CHARA CTE RIZA TI 0 N ..........................................................................................
MOTORS.........
................................................................................................................... .......................
LIGHT COMMERCIAL HV AC EQUIPMENT.................................................................................................
LIGHTIN"G EQUIPMENT ............................................................................................................................
SECTION 3 REVIEW OF OTHER UTILITY DSM PROGRAMS .............................................................
MOTOR DSM PROGRAMS .........................................................................................................................
HV AC DSM PROGRAMS ............................................................
.............................................................
LIGHTIN"G EQUIPMENT INCENTIVE PROGRAMS................
.................................................... ................... ..
SECTION 4 REC 0 MMEND A TIO N S.............................................................................................................
SECTION 5 POTENTIAL SAVINGS ANALYSIS ........................................................................................
PREMIUM EFFICIENCY MOTORS ...............................................................................................................
HIGH EFFICIENCY LIGHT COMMERCIAL HV AC EQUIPMENT ....................................................................
LIGHTIN"G EQUIPMENT ..............................................................................................................................
SECTION 6 REFE REN C ES.......
........................ .......... ............................. .......................... ....... ............... .......
SECTION 7 APPEND ICES .......... ................................ ......
...... ....................... ............................. ....................
7 -
'-'1 NexanT FinAnswer Express Market Potential Assessment for Idaho
Executive Summary
In an effort to realize available energy savings opportunities associated with high efficiency
motor, light commercial HV AC, and lighting equipment within PacifiCorp s Idaho service
territory, potential energy efficiency program options have been evaluated. Specially, this report
summarizes the results Nexant, Inc. has completed in estimating the available savings potential
and associated costs with introducing PacifiCorp s FinAnswer(ID Express program into this
market. Findings presented here were derived from a variety of sources, including:
The results of interviews and surveys recently conducted with key market players within
PacifiCorp s service territories;
A review of current market data and trends;
The performance of the FinAnswer Express program in other PacifiCorp service
territories, and;
Nexant's experience in implementing similar Demand Side Management (DSM)
programs around the country.
As a result of this work, Nexant recommends that if PacifiCorp s current FinAnswer Express
Program is introduced Idaho, that the following changes be made to the program delivery
mechanism:
Prescriptive incentives for variable frequency drives (VFDs) installed on HV AC system
fans and chilled water pumps
-:::
100 hp be added.
Incentives for red LED traffic signals be discontinued in recognition that this measure has
been accepted as current practice in the marketplace.
Minimum efficiency requirements for packaged and split -system unitary equipment
-:::65 000 Btu/h be increased to 15 SEER/12.5 EER.
The 25 000 CFM size limitation on evaporative equipment be removed.
Table i summarizes the estimated incentives, customer costs, and savings impacts associated
with implementing the FinAnswer Express program in Idaho with the aforementioned
modifications.
L-1 NeKanr FinAnswer Express Market Potential Assessment for Idaho
Table i. Potential FinAnswer Express program impacts in Idaho. 1
Net Net Annual Net Peak
Year Incentives Customer Energy Demand
Incremental Savings Savings
Costs 2 (kWh) 3 (kW) 4
Motors
Year 1 632 $998 023
Year 2 601 $14 537 904
Unitary HV
Year 1 $ 1 700 $ 3 264 979
Year 2 $ 3,450 $ 6,624 987
Evaporative
Year 1 $294 $ (3 680)127
Year 2 $ 605 $ (7 581)322
VFDs
Year 1 $12 800 $31 027 115 680
Year 2 $19,200 $46 541 173,520
Lighting
Year 1 $ 28,314 $93,952 210,185
Year 2 $ 56,441 $187 287 418,987
Total
Year 1 $44 740 $125,561 332 994
Year 2 $82 297 $247,408 604 720
1 Estimates are for a full year program period.
2 Customer costs represent the net values inclusive of free-ridership estimates, but do not
include the impacts of available incentives.
3 Energy savings reflect net impacts at the customer meter with an assumed net-to-gross
ratio of 0.96 (Express Efficiency Program Offering, DEER 2005).
4 Demand savings reflect net impacts at the customer meter with an assumed net-to-gross
ratio of 0.96 (Express Efficiency Program Offering, DEER 2005), and a coincident demand
factor of 0., and 0.70 for motors, HVAC (unitary and evaporative) and lighting
equipment, respectively (PG&E 2001).
'-1 Nexanr IIIFinAnswer Express Market Potential Assessment for Idaho
Section Introduction
This report summarizes work completed by Nexant, Inc. in conducting a market assessment of
the savings potential associated with introducing PacifiCorp s FinAnswer Express program into
the Idaho service territory. The FinAnswer Express program provides prescriptive incentives for
the purchase and installation of qualifying high efficiency motors, HV AC, and lighting
equipment. This program structure targets smaller, less complex energy efficiency projects and
equipment replacement opportunities in the market.
Estimated savings and cost data presented in this report were determined by building upon the
market assessment activities conducted in 2003 in support of the original design of the
FinAnswer Express program for PacifiCorp s Utah and Washington service territories. As part of
those initial activities, thirteen motor manufacturer representatives, twenty-five HV AC
manufacturer representatives and large mechanical contractors, and sixteen lighting contractors
and system designers were interviewed by or submitted completed surveys to Nexant. This
feedback was supplemented by analyses of existing market trends, performance of the FinAnswer
Express program in Utah and Washington, and similar other programs around the country.
The balance of this report is structured as follows:
Section 2 provides an overview of the current markets within Idaho. Estimates of the
annual sales volume and the percentage of high efficiency equipment installations are
provided, as are estimates of the savings potential and incremental customer costs
associated with qualifying high efficiency equipment;
Section 3 presents an overview of other utility incentive programs targeting premium
efficiency motors, HV AC, and lighting equipment;
Section 4 includes Nexant's recommended modification to the current FinAnswer
Express Program before introducing it to the Idaho market;
Section 5 summarizes the potential costs and savings associated with implementing the
FinAnswer Express program in the Idaho market;
Section 6 lists key reference materials used to develop this report, and;
Section 7 contains several appendices of supplemental information.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 2 Market Characterization
Based on the survey responses and market research efforts conducted by Nexant, the following is
an overview of the current motor, light commercial HV AC, and lighting equipment markets and
sales trends in Idaho. General information on the potential savings and incremental costs
associated with high efficiency equipment is also provided.
MOTORS
Market Snapshot
Electric motor-driven systems consume more than a quarter of all electricity sold in the United
States, making up the largest single category of electric end-use.
1.1 Equipment manufacturers and representatives
Eight major manufacturers account for the majority of commercial motors sold into the Idaho
market. Leeson and Baldor appear to be dominant players, while secondary players include GE
Teco- Westinghouse, US Motors, AO Smith, Lincoln, and Siemens.
Manufacturer representatives and distributors typically push motors to the market. These
distribution channels may be represented by manufacturer-employed representatives working for
companies such as Leeson or Teco-Westinghouse, or through independently owned firms like
S&G Electric or Kaman Industrial Technologies.
Most of the contacted parties did not have software products available that would allow them to
estimate the annual operating costs and potential savings available with high efficiency
equipment for their customers.
Sales process
Based on feedback from some of the survey participants, only about 10% of new motors sold will
become inventory within a customer s facility while the remainders are placed into service within
a short period after the sale. Electric motor sales are typically driven by one of three factors:
equipment failure, planned replacement, or new construction. Table 1 summarizes the survey
respondents' feedback across these categories.
Table 1. Electric motor sales drivers.
Reason for Equipment Sale Percentage
Equipment Failure 560/0
Planned Replacement 160
New Construction 220
Other 60/0
Total 1000/0
(,,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
When new motors are purchased, survey respondents indicate that the key decision maker in the
process is generally the building owner or the facility manager. Table 2 summarizes these
responses.
Table 2. Key decision maker in electric motor sales.
Key Decision Maker Percentage
Building Owner 550
A&E Firm 310
Contractor
Other 40/0
Total 1000/0
1.1.3 Equipment stocking practice and seasonal sales trends
Survey respondents indicate that the majority of electric motors sales are filled utilizing the
manufacturers' inventory, although a small number of standard and premium efficiency units are
kept in local inventory for failed equipment replacements. Table 3 summarizes the survey
respondents' inventory practices.
Table 3. Electric motor stocking practices.
Percentage Sold from Percentage Sold from
Size Category ManufacturerLocal Inventory (0/0)Inventory (%)
1 - 5 hp 230/0 770
6 - 20 hp 230 770
21 - 50 hp 220/0 780
51 -100 hp 200 800
101 - 200 hp 140/0 860/0
Finally, seasonality does not seem to playa role in the sales volume of electric motors. This is
especially true for motors purchased due to failed equipment. It seems reasonable to expect some
seasonality due to new construction purchases, however the survey responses received provided
insufficient data to draw any conclusions.
Annual Sales Volume in Idaho
Due to the variety of distribution channels for electric motors and the unwillingness of some
survey respondents to disclose sales data, a top-down approach was used to estimate the annual
sales volume of electric motors in Idaho.
Table 4 presents the estimated sales within the state based upon a pro-rated comparison of the
ratio of Idaho s real GrtJ"s State Product versus the U.S. real Gross Domestic P:"-.Iduct applied to
the 2001 Census Bureau s report on Motors and Generators. This estimate takes into account
imports and exports as reported by the Census Bureau. The portion of sales within PacifiCorp
""
Nexanr FinAnswer Express Market Potential Assessment for Idaho 2-
Section Market Characterization
service territory, estimated by applying a fixed ratio of PacifiCorp s commercial customers to the
state total, is also provided (EIA 1994-2002).
Table 4. Electric motor sales in Idaho (2001).
Estimated Total Estimated Units
Size Category Units Sold Sold in PacifiCorp
10 Service Territory
1 - 5 hp 021 275
6 - 20 hp 065 141
21 - 50 hp 605
51 -100 hp 203
101 - 200 hp 100
Total 994 478
Current Sales of Premium Efficiency Motors
The market for electric motors meeting NEMA's Premium Efficiency standards is robust and
expanding, accounting for approximately 15% of national motor sales for units in the 1 to 200 hp
size range. Survey respondents, although varied, seemed to confirm the validity of the national
trend. Table 5 is based on the sales volumes shown in Section 2.1.2 and the assumption that 15%
of total motor sales are Premium Efficient motors.
Table 5. Premium efficiency motor sales in
PacifiCorp s Idaho service territory (2001).
Size Category Premium Efficiency
Sales
1 - 5 hp
6 - 20 hp
21 - 50 hp
51 -100 hp
101 - 200 hp
Total
Incremental Energy and Demand Savings Potential
Many factors combine to determine the energy and demand savings potential for premium
efficiency motors, although the most salient ones include operating hours, load factor, and the
change in efficiency.
Based upon results from ESource and Nexant's experience, predicted gross energy and demand
savings were derived based on the following equations (ESource 2003):
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
kW _Savings = (0.746 X HPx Load _Factor)x
EP Act eff EP Act eff delta eff
kWh Savings kW _Savings Hours
Where hp is the motor size and Hours are the average operating hours based on ESource reported
average hours of industrial motors, adjusted to reflect the estimated mix of commercial and
industrial motor applications within the state (Esource 2003, EIA 1994-2002). Load Factor
based on numerous sources, including ESource, that all indicate an average of 50% for lower hp
motors increasing to an average 70% load for larger motors. delta eff is derived based on
incremental efficiency gains over EP Act as reported by ESource. Key assumptions and resulting
net savings estimates for premium efficiency motors from 1 to 200 hp are summarized in Table
Table 6. Motor savings calculation parameters and values.
Energy Demand
Hours Load Factor EPAct eff delta eft Savings Savings
(kWh/motor)(kW /motor)
2721 500/0 80.1 %70/0
2721 500 83.60/0
2721 500/0 84.90/0 101
2721 500/0 86.30/0 60/0 137
2721 500 87.00/0 184
3207 500/0 88.335
3207 500 89.50/0 1 %426
3207 500/0 90.40 30/0 473
3207 500 90.50/0 690
3624 600/0 91.60/0 012
3624 600 91.2.40 280
3624 600/0 92.1,400
3624 600/0 92.20/0 914
4663 500/0 93.40 954
4663 500 93.1 .60/0 250
100 4663 500/0 93.979 0.47
125 4971 700/0 94.20/0 5,408
150 4971 700 94.1.40 627
200 4971 700 94.30/0 107
1 Savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.96 (Express Efficiency Program
Offering, DEER 2005) and a coincident demand factor of 0.74 (PG&E 2001).
Full-load motor speed may also impact motor savings. The full-load speed of EP Act and
premium efficiency motors can vary as much as 4% within a given efficiency classification. In
addition, the range of full-load speeds will be slightly higher for premium efficiency motors then
for their less efficient counterparts. Although the variance within a range can be as much as 4%
the difference 1,)tween the ranges (between EPAct and premium effici( ~~cy) is much less. This is
due to the fact that the ranges overlap. The potential increase in speed may have a negative
impact on energy use and demand if the end use is a constant speed centrifugal load, although it
(1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
can be minimized or eliminated with proper motor selection. For this reason, the issue of motor
speed changes was not considered in the savings calculations.
Estimates of Incremental Customer Costs
Incremental customer costs are cited by numerous references as having little correlation to
horsepower and efficiency. It is suspected that this is due to varying manufacturers discounts and
various market conditions that may influence discounts and pricing on a monthly basis. For the
analysis presented in this report, Nexant used average price premiums derived from MotorMaster
and presented in ESource (ESource 2003). The average gross price premiums are shown in Table
7 and do not reflect the impacts of free-ridership or utility incentives.
Table 7. Gross customer price premiums derived from MotorMaster.
Motor hp Open Drip Proof Totally Enclosed Fan Cooled Average3600 rpm 1800 rpm 1200 rpm 3600 rpm 1800 rpm 1200 rpm
104
146
121
137 (47)
192
144 118 103 242 120
106 175 164 (19)265 129
127 130 175 130 205 285 175
122 111 263 194 190 162
160 186 344 417 447 512 344
114 524 311 378 345 355 338
224 116 426 567 234 196 294
119 489 540 434 279
100 201 281 496 397 112 1 ,300 465
125 421 216 190 281 $ 1 000 $ 1 321 572
150 502 608 289 374 570 645 498
200 794 564 1 ,065 $ 1 171 541 1 ,632 961
LIGHT COMMERCIAL HV AC EQUIPMENT
Market Snapshot
Equipment manufacturers and representatives
Nationally, eight major manufacturers account for nearly all commercial unitary cooling
equipment production. Carrier, Lennox and Trane equipment appear to dominate the Idaho
market. Likewise for evaporative cooling equipment, there are approximately a half-dozen major
manufacturers nationally, with Champion and Phoenix products leading the Idaho market.
Manufc - turer representatives and distributors typically push co; mercial cooling equipment to
the market. These distribution channels may be represented by manufacturer-employed workers
such as Lennox, or through independently owned firms like Carrier-Intermountain.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
All major manufacturers have software products available that can be used to inform customers
of the annual operating costs and potential savings available with high efficiency equipment. In
general, respondents to the surveys were familiar with and capable of using these tools or other
commercially available software packages, but rarely did so in practice due to the limited sales of
high efficiency equipment.
Supplemental information regarding packaged-terminal air conditioners and heat pumps (PT
and PTHP) is provided in Appendix E of this report.
Sales Process
The sale of light commercial HV AC equipment is typically driven by one of three factors:
equipment failure, planned replacement, or new construction. Table 8 summarizes the survey
respondents ' breakdown between these categories.
Table 8. Commercial HV AC equipment sales drivers.
Reason for Equipment Sale Percentage
Equipment Failure 250/0
Planned Replacement 180
New Construction 570/0
Other
Total 1000/0
When new commercial cooling equipment is purchased, survey respondents indicate that the key
decision maker in the process the contractor. Table 9 summarizes these responses.
Table 9. Key decision maker in HV AC equipment sales.
Key Decision Maker Percentage
Building Owner
A&E Firm 140/0
Contractor 690
Other
Total 1000/0
Commercial HV AC equipment stocking practice and seasonal sales trends
Survey respondents indicate that a majority of both small and large unitary equipment is sold
from manufacturer inventory, although a small number of standard efficiency units are kept in
local inventory for failed equipment replacements. For unitary equipment over 5 tons, no
respondent indicated that high efficiency models are stocked locally. Table 10 summarizes the
survey respondents' inventory practices.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
Table 10. Commercial unitary equipment stocking practices.
Percentage Sold from Percentage Sold from
Man ufactu rerSize Category Local Inventory Inventory(0/0)(0/0)
65,000 Btu/h ~1 00 :::-900
:::- 65,000 Btu/h &150 850/0135000 Btu/h
:::- 135 000 Btu/h &~1 00 :::-900/0240000 Btu/h
:::- 240 000 Btu/h 21 %790/0
Finally, unlike the residential cooling equipment market, the commercial market is less
seasonally driven, although summer months still account for a significant portion of equipment
sales. Reported sales information by quarter and type is presented in Table 11.
Table 11. Commercial HV AC cooling equipment sales timing patterns.
Date Equipment Planned New
of Sale Failure Replacement Construction
/0)(0/0)
(%)
1 st Quarter (Jan-Mar)130 200/0 190
2nd Quarter (Apr-Jun)330/0 400/0 31 %
3rd Quarter (Jul-Sep)440/0 1 00/0 260
th Quarter (Oct-Dee)1 00 300 240
Total 1000/0 1000/0 1000/0
Annual Commercial HVAC Sales Volume in Idaho
Due to the variety of distribution channels for light commercial HV AC equipment and the
unwillingness of some survey respondents to disclose sales data, a top-down approach has been
used to estimate the annual sales volume of HV AC equipment in Idaho.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
Results from the 1999 Commercial Building Energy Consumption Survey (DOE/EIA 2002), or
CBECS, were used to estimate the penetration of unitary and evaporative cooling equipment in
the commercial market sector. Reported values for the Mountain Census Division were used and
linearly adjusted for Idaho based on state populations. An overview of the HV AC equipment
used to provide cooling in Idaho s commercial buildings is presented in Figure
II)';' B 0or- 0.- 0 0II) 0 aC) - 0LO or-
.-
C\I
. packaged ac
D evaporative
. residential central ac
Ii room ac
II chiller
13 heat purrp
13 district chilled water
10%20%30%40%50%
Percent of floor space cooled
(%)
Figure 1. Commercial cooling equipment types by floor space in Idaho.
For the purpose of estimating annual sales of light commercial HV AC equipment, the CBECS
classifications of residential central AC equipment, packaged AC equipment, and heat pumps
were categorized as unitary equipment. Evaporative equipment was evaluated separately. Table
12 summarizes the estimated annual sales volumes of light commercial HV AC equipment in
PacifiCorp s Idaho service territory.
Table 12. Estimated annual sales of light commercial HVAC equipment in ID service territory.
Replaced New Unitary Total Replaced New Total
Unitary Unitary Evaporative Evaporative EvaporativeYearEquipmentEquipmentSalesEquipmentEquipmentEquipment(tons)(tons)(tons)000 CFM)000 CFM)000 CFM)
2004 1 ,452 081 532 634 472 106
2005 ,495 113 608 653 486 139
2006 540 146 686 673 501 173
2007 586 181 767 693 516 209
A number of key assumptions were built into the estimated sales volume values shown in Table
12. They include:
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
An average equipment lifetime of 15 years (ASHRAE 2003);
A conservative 3% growth rate in new commercial customers (EIA 1994-2002), and;
A steady evaporative cooling equipment market.
Based on the information reported by contacted parties, these estimates of annual sales volume
appear to be reasonable.
Current Sales of Commercial High Efficiency HV AC Equipment
Based on interviews with key light commercial HV AC equipment manufacturer representatives
and distributors, sales of unitary equipment with efficiency levels that meet or exceed the
Consortium for Energy Efficiency s (CEE) Tier 2 levels, are very limited (c( 5%). Sales of unitary
equipment that meet ASHRAE 90.1999 requirements (same as CEE's Tier 1) are slightly
higher (10%-20%), but still limited. Respondents cited two key reasons:
The commercial unitary equipment market is extremely competitive and driven by first
costs. Contractors especially are unwilling to pay a premium for high efficiency
equipment and place themselves at a disadvantage when responding to competitive bids.
Building owners, contractors , and A&E firms are unfamiliar with the true costs of
standard efficiency equipment as compared to high efficiency options and prefer to stick
to the status quo when selecting commercial cooling equipment.
Incremental Energy and Demand Savings Potential
Due to the wide variety of commercial cooling equipment available and the manner in which it is
used, Nexant has developed savings estimates that are expected to be representative of both high
efficiency unitary and evaporative units in a typical commercial application
Current commercial building codes in Idaho are based on ASHRAE Standard 90.1999. Savings
estimates provided here assume new high efficiency HV AC equipment that just meets current
program eligibility requirements, which are the same as the Consortium for Energy Efficiency
(CEE) Tier 2 efficiency levels.! These savings estimates are shown in Table 13 and were used to
estimate the potential program savings impacts in Section 5 of this report.
1 Effective January 23, 2006, the federal minimum efficiency for split and packaged unitary equipment c:::: 65,000
Btu/hr will increase to 13 SEER. As stated in Section 4, minimum efficiency requirements of 15 SEER/12.5 EER
are recommended for this size category of HV AC equipment.
1.,,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
Table 13. Representative commercial cooling equipment
energy savings estimates for Idaho.
Equipment Net Annual Net Peak
Energy Savings Demand SavingsType(kWh)(W)
Unitary 2 29/ton 57/ton
Evaporative 3 077/CFM 39/CFM
1 Savings calculated for a commercial office building in Pocatello
Idaho with operation M-F from 7:00 a.m. to 7:00 p.m. Indoor set
point of 75 of with dry-bulb economizer. This location used as
most representative of the PacifiCorp I D service territory where
unitary equipment performance data was available.
2 Savings estimates are representative of equipment from 5 to 20
tons in size. Savings reflect net impacts at the customer meter with
an assumed net-to-gross ratio of 0.96 (Express Efficiency Program
Offering, DEER 2005) and a coincident demand factor of 0.
(PG&E 2001).
3 Savings estimates are valid for evaporative equipment in
comparison to a unitary system that meets the appropriate baseline
efficiency requirement. Savings reflect net impacts at the customer
meter with an assumed net-to-gross ratio of 0.96 for evaporative
equipment (Express Efficiency Program Offering, DEER 2005), and
a coincident demand factor of 0.87 (PG&E 2001).
In support of the recommendations to offer incentives for VFDs installed on HV AC system fans
and 100 hp provided in Section 4 of this report, the estimated net annual energy savings at the
meter for this measure is 723 kWh/Yf/hp (PG&E 2005). The corresponding savings estimate for
VFDs installed on chilled water pumps 100 hp is 565 kWh/Yf/hp. These savings estimate
includes a net-to-gross estimate of 0.96. There are no estimated demand savings associated with
this measure.
Estimates of Incremental Customer Costs
Based on independent published reports and survey results, the estimated average incremental
customer cost for unitary equipment that meets program minimum requirements is $75-100 per
ton, based on the size and type of equipment. This price increase represents approximately a 15%
premium in customer cost for high efficiency equipment. Estimated incremental costs for various
sizes of high efficiency HV AC equipment are listed in Table 14 (CEE, 2003b; Center for Energy
and Environment, 1999; survey respondents).
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
Table 14. Estimated incremental HV AC equipment costs.
HVAC Equipment Size Incremental Cost
(tons)($/ton)
-:::5 $ 180.
$ 72.
$ 85.
12.$ 100.
$ 73.47
$ 84.
Gross incremental costs between current HV
equipment sales in Idaho and qualifying HV AC equipment
Prices do not reflect impacts of free-ridership or utility
incentives.
When compared to standard efficiency unitary equipment, commercial evaporative cooling
equipment is typically less expensive, on the order of 50% to 70% of corresponding unitary
equipment costs.
The estimated gross customer incremental cost for VFDs installed on HV AC system fans c::::100
hp is $202/hp, while the corresponding value for VFD retrofits on chilled water pumping systems
is $382/hp (PG&E 2005).
LIGHTING EQUIPMENT
Market Snapshot
Equipment manufacturers and representatives
The lighting industry is fairly established and consistent throughout the country. The majority of
lighting equipment is manufactured by a handful of companies such as GE, Philips, Sylvania
Advance, and Howard Industries. Lighting equipment is readily available on a national level and
no one player was found to dominate the Idaho market. Electrical supply houses and equipment
wholesalers typically push commercial lighting equipment to the market through installation
contractors.
There are a number of commercially available software packages available to help estimate the
annual operating costs and potential savings available with high efficiency lighting equipment.
By far the most commonly reported tools used by lighting professionals (70%+), however, were
custom in-house developed spreadsheets and savings algorithms.
Sales process
The sale of lighting equipment is typically driven by a variety of factors. Table 15 summarizes
the key reasons identified by survey respondents.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
Table 15. Lighting equipment sales drivers.
Reason for Equipment Sale Percentage
Equipment Failure
Planned System Upgrade 1 90/0
Unsolicited Proposal 300
Tenant Improvement (TI)140
New Construction 270
Total 1000/0
When new or replacement lighting equipment is purchased, survey respondents indicate that the
key decision maker in the process is driven by the building owner, although the lighting designer
and contractor do playa critical role as well. Table 16 summarizes these responses.
Table 16. Key decision maker in lighting equipment sales.
Key Decision Maker Percentage
Building Owner 54 %
A&E Firm/Lighting Designer 230/0
Contractor 1 90
Maintenance
Total 1000/0
Annual Sales Volume in Idaho
Due to the volume of distribution channels for lighting equipment and cost associated with
surveying all lighting companies, a top-down approach has been used to estimate the annual sales
volume of lighting equipment in Idaho.
Results from the 1999 CBECS (DOE/EIA 2002), EIA reported sales data (EIA 1994-2002), and
the ESource Lighting Atlas (ESource 1997) were used to estimate the annual sales volume of
lighting equipment in the commercial market sector in Idaho. Table 17 summarizes the estimated
annual sales volumes of lighting equipment in PacifiCorp s Idaho service territory.
Table 17. Estimated annual sales of lighting equipment in Idaho service territory.
Retrofits New Total SalesYearConstruction($1 000s)($1 000s)($1 000s)
2004 $ 3 938 $ 2 932 $ 6,870
2005 $ 4 057 $ 3 019 $ 7 076
2006 $ 4 178 $ 3 110 $ 7 288
2007 $ 4 304 $ 3,203 $ 7 507
(1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Market Characterization
A number of assumptions were built into the estimated sales volume values shown in Table 17
including:
An average equipment lifetime of 15 years, and;
. A conservative 3% growth rate in new commercial customers (EIA 1994-2002).
Based on the information reported by contacted parties, these estimates of annual sales volume
appear to be reasonable.
Current Sales of High Efficiency Lighting
Based on survey responses, current sales of high efficiency lighting equipment constitute a
respectable percentage of total sales. Reported sales patterns by major lighting equipment
category are shown in Table 18.
Table 18. Reported distribution of lighting equipment sales.
Linear Fluorescent High Intensity Discharge Other
(0/0)(0/0)(0/0)
T12 80/0 Mercury Vapor Incandescent 130
740/0 High Pressure Sodium 130/0 Halogen 370
Enhanced" T8 1 00/0 Metal Halide 210/0 Screw-in CFL 110/0
T5 (inc!. High Bay)80/0 Pulse Start MH 590/0 Hardwired CFL 400
Total 1000/0 Total 1000/0 Total 1000/0
Incremental Energy and Demand Savings Potential
Appendix D contains a listing of the estimated incremental energy and demand savings potential
for specific lighting fixture retrofits or upgrades for both retrofit and new construction measures.
Across the entire non-residential market sector, the estimated gross average energy and
coincident peak demand savings potential from high efficiency lighting equipment are 1.
kWh/sqft-Yf and 0.3 W/sqft respectively.
Estimates of Incremental Customer Costs
Appendix D contains a listing of the estimated incremental customer costs for specific lighting
fixture retrofits or upgrades. Across the entire non-residential market sector, the estimated
average gross incremental customer cost is $0.82/sqft.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 3 Review of Other Utility DSM Programs
Nexant completed a review of similar DSM programs targeting premium efficiency motors
HV AC equipment, and lighting equipment to characterize successful program traits implemented
by other utilities. These programs were reviewed in greater detail to assess program
implementation details including:
Program participation and application requirements;
Eligible project types;
The incentive delivery mechanism;
The extent of any supporting Trade Ally infrastructure, and;
How program savings are determined.
Results of this benchmarking effort are described below.
MOTOR DSM PROGRAMS
Six premium efficiency electric motor incentive programs were investigated in detail. The
programs reviewed included:
Industrial Efficiency Incentive Program. Idaho Power s energy efficiency program
available to commercial and industrial customers in Idaho Power s service territory.
Incentives are available for retrofit applications if authorized prior to installation.
Incentives are reserved for one calendar year.
Idaho Premium Efficiency Motors Program. A vista s energy efficiency program is
available to commercial and industrial customers in their service territory who wish to
install premium efficiency motors in new and retrofit applications. Incentives are only
available if pre-authorized and are payable via customer check or utility bill credit.
Energy Conservation Loan Program. Idaho s Department of Water Resources provides
low-interest loans to install energy conservation measures with payback periods of less
than 15 years. Eligible measures for non-residential users energy-efficient lighting,
HV AC improvements, and retrofitting pumps and motors.
MotorUp. A premium efficiency motor initiative directed by 20 electric utilities across 7
states and administered by a third party. Incentives are available for retrofit or new-
construction and for installation or for stock.
Upstream Motors Air Conditioning Program. California s statewide prescriptive
incentive program directed by the California Public Utilities Commission and
administered by the four IOUs in the state. Incentives are available for retrofit projects
and motors must be installed within the program year.
Nevada Sure Bet. Sierra Pacific Resource s energy efficiency program available to
customers of their two subsidiary IOUs ir the state of Nevada. Incentives are available for
retrofit or new-construction and motors must be installed within the program year.
(,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
The three programs in Idaho allow premium efficiency motors as qualifying measures. Idaho
Power s Industrial Efficiency Incentive Program is a comprehensive program that pays incentives
for motors based upon the lesser of project cost or energy savings. A vista s Idaho Premium
Efficiency Motors Program provides prescriptive incentives for premium efficiency motors in
new and retrofit applications through a pre-purchase incentive agreement. Incentives vary
depending on whether the motor operates continuously. The Idaho Department of Water
Resources offers loans for energy efficient upgrades where the energy cost savings exceeds 10%
of the project cost. The loan application process is flexible, allowing the applicant to choose how
to portray the technical feasibility of the project.
The three out of state programs shared some common traits, including:
Qualifying motors are 1 - 200 horsepower NEMA A & B , 3-phase, integral horsepower;
Use of a stipulated 75% motor load factor for savings calculations;
A post -purchase customer application process requiring the following:
Customer information (name, address, building type, utility account number, etc.
Equipment information (make, model, size, efficiency, date of purchase, etc.
Dealer information;
Customer information, and;
Detailed equipment invoice.
Table 19 provides a summary of the incentive levels, eligible market sectors, incentive payment
process, and trade ally support services for each of the programs.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
Table 19. Other utility motor incentive program design parameters.
Incentive Eligible Application Incentive
Program Organization levels Project Procedure Payment Trade Ally Support
Types Process
$10 - $660 per
motor based on
hp (continuous
Idaho operation)Customer
Premium Avista $10-$390 per Retrofit and Pre-notification Check or
Efficiency Corporation motor based New required.Credit None
Motors upon hp (non-Construction against
Program continuous Utility bill
operation)
No dealer
incentives
Customer
incentive is based Pre-notification isIndustrialon the lesser of required andEfficiencyenergy savings,Customer
Incentive Idaho Power 50% of project Retrofit rebates are Check Program 800 number
Program cost, or the one reserved for one
year simple calendar year.
payback amount.
Energy Idaho 000-Retrofit and Pre-Approval is
Conservation Department of $100,000 loan limited new required Loan NoneLoanWaterat 4% interest construction
Program Resources rate measures
$45 - $700 per The application
motor based on may be submitted
hp and type after the Monthly Newsletter
Various Utilities Dealer Retrofit and equipment is Customer Marketing, Marketing
MotorUp in seven North incentives of New Materials, MotorMaster
Eastern states $25/application Construction installed. Pre-Check Motor Management
were approval from the Training
discontinued for individual utilities2003may be required.
Distributor-based
Dealer program where
Incentives Application is
participating vendors
sign agreement, online
$25 - $880 per submitted by equipment database,
Upstream PG&E, SoCal motor based on distributor online Distributor &and electronic submittal
Motors & Air process. Distributors
Conditioning Edison, SoCal Customer Retrofit with invoice.Customer are the key market
Program Gas, SDG&E Incentives Customer may Checks players. Account
$10 - $380 per submit for representatives and
motor based on incentive online.general office personnel
support the
informational needs of
the vendor public
Pre-notification
$10 - $350 per required for
Nevada Power motor based on Retrofit and prescriptive
Nevada Sure Company &New programs over Customer Program 800 number
Bet Sierra Pacific No dealer Construction $10,000 and Check and quarterly seminars
Power Company custom projectsincentivesover $7500 in
incentives.
1 Customers can elect to have the incentive S",,1t to a third party as designated on the application form.
'-'1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
In general, program savings for the programs listed in Table 19 were calculated rather than
measured. The calculated approaches to program savings are as follows:
Idaho Premium Efficiency Motors Program. A vista s program calculates savings for each
motor in the program. The program calculations stipulate an EP Act baseline motor
efficiency, a NEMA Premium efficiency replacement motor, a stipulated motor load
factor, and stipulated annual run-hours depending whether the motor operates
continuously or non-continuously.
MotorUp: The MotorUp program calculates savings for each motor in the program. The
program calculations stipulate an EP Act baseline motor efficiency, a NEMA Premium
efficiency replacement motor, a fixed 75% motor load factor, and a variable annual run-
hours as reported on the incentive application (program has a 2 000 hour minimum).
Upstream Motors Air Conditioning Program and Nevada Sure Bet: Both program
designs utilized the same methodology for calculating program savings. As with
MotorUp, savings are calculated for each motor in the program. The calculations assume
a baseline motor efficiency as follows:
c( 20 hp: Baseline is assumed to be EPAct efficiency, and;
::::-
20hp: Baseline is assumed to be EPAct efficiency less 2.0% (assumed to be
rewound).
The baseline motor efficiency is stipulated as NEMA Premium standards, motor load is
stipulated at 75%, and annual run hours are fixed at 4 700. In addition, program demand
savings are calculated using a coincident diversity factor of 74%.
HV AC DSM PROGRAMS
Idaho has three programs that provide incentives for HV AC related upgrades:
Industrial Efficiency Incentive Program. Idaho Power s energy efficiency program
available to commercial and industrial customers in Idaho Power s service territory.
Incentives are available for retrofit and new construction applications if authorized prior
to installation. Incentives are reserved for one calendar year.
Washington Idaho Energy Efficiency Incentives. Avista s energy efficiency program
available its commercial and industrial customers. Incentives are available for retrofit and
new construction applications if authorized prior to installation. Incentives are capped at
50% of the project cost.
Air Care Plus Program. Avista pays for diagnosing and tuning existing commercial
rooftop HV AC systems up to 15 tons in size. The program covers the cost of the service,
but there are no incentives for capital improvements or replacement with new equipment.
Four additional out of state high efficiency HV AC incentive programs were investigated in
detail. The programs reviewed in luded:
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
Upstream Motors Air Conditioning Program Express Efficiency. California
statewide prescriptive incentive program directed by the California Public Utilities
Commission and administered by the four IOU s in the state. In 2004 split and packaged
air conditioning equipment were pulled from the Express Efficiency Program and
directed through the 2004 Upstream Motors & Air Conditioning Program. Incentives for
package terminal air conditioners and heat pumps can be accessed through the Express
Efficiency Program.
Nevada Sure Bet. Sierra Pacific Resource s energy efficiency program available to
customers of their two subsidiary IOUs in the state of Nevada.
Cool Choice. The commercial HV AC energy efficiency initiative developed by the
Northeast Energy Efficiency Partnership (NEEP) and administered across thirteen utility
service territories in Massachusetts, New Jersey, Rhode Island, and Vermont.
$mart Equipment Choices. Commercial HV AC incentive program offered by the New
York State Energy Research and Development Authority (NYSERDA).
These four programs shared some common traits, including:
Use of the Consortium for Energy Efficiency s (CEE) Tier 2 standards as minimum
equipment efficiency requirements;
A post-purchase customer application process requiring the following:
Customer information (name, address, building type, utility account number, etc.
Equipment information (make, model, size, efficiency, serial number, etc.
Dealer information;
Customer information, and;
Equipment invoice.
No equipment sizing requirements, and;
No dealer or distributor incentives.
Determination of estimated savings impacts for each of the programs were very similar as well
relying on calculated rather than measured values. Demand savings were estimated using the
difference in nameplate efficiencies between the installed unit and the minimum efficiency
allowed by local code. Estimates of annual energy savings were calculated by multiplying the
estimated demand savings by the assumed equivalent full load cooling hours. The Cool Choice
program applied a de-rating factor of 0.9 to the energy savings calculation. The effects of various
building types and part-load equipment efficiencies were not directly addressed by any program
when estimating savings impacts. Adjustments for peak coincident use, transmission line losses
and the effects of free-ridership were typically applied to propagate calculated savings at the
customer meter back to the g':1'J.erating plant.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
Finally, Table 20 and Table 21 provide a summary of the incentive levels, eligible project types
incentive payment process, and trade ally support services for each of the programs.
Table 20. HV AC DSM program incentive levels.
Equipment Type Express $mart
Efficiency/Upstream HV Nevada Sure Bet Cool Choice Equipmentand Size Program 2 Choices 3
PTAC & PTHP Customer Dealer
000 Btu/hr or less $100/unit N/A N/A $45/ton
:;:. 7 000 to 9 500 $100/unit N/A N/A $45/ton
:;:. 9 500 to 15 000 $100/unit N/A N/A $45/ton
:;:. 15 000 $100/unit N/A N/A $45/ton
Air Source AC & HP
:5. 65 000 $80-140 /unit $205-541 /unit $25/ton + (11new -11base
) *
$92/ton $40/ton
:;:. 65 000 to 135,000 $75.00/unit $79.00/unit $30/ton $73/ton $40/ton
:;:. 135,000 to 240,000 $75.00/unit $79.00/unit $40/ton + (11new -11base
) *
$79/ton $40/ton
:;:. 240 000 $75.00/unit $79.00/unit $30/ton $79/ton N/A
Water Source AC & HP $40/ton + (11new -11base
) *
:5. 65,000 N/A N/A $30/ton $81/ton $140/ton
:;:. 65,000 to 135 000 N/A N/A $40/ton + (11new -11base
) *
$81/ton $127/ton
:;:. 135 000 to 240 000 $113/unit $79/unit $30/ton $81/ton $96/ton
:;:. 240 000 N/A N/A $81/ton N/A
$25/ton + (11new -11base
) *
$80/ton
$25/ton + (11new -11base
) *
$80/ton
$25/ton + (11new -11base
) *
$80/ton
$25/ton + (11new -11base
) *
$80/ton
Unless otherwise noted, minimum efficiency requirements are consistent with CEE's Tier 2 levels.
2 Minimum PT AC and PTHP EER values are given by: 10.0 - (0.16 X Capacity in Btu/hr)/1000. Minimum capacity of 7 000 Btu/hr and
maximum capacity of 15,000 Btu/hr to calculate minimum efficiency.
3 Minimum PTAC and PTHP EER values are as follows: 7 000 Btu/hr and less -11.7 EER/3.3 COP; 7 000 to 9 500 - 11.3 EER/3.2 COP;
500 to 15 000 - 10.7 EER/3.1 COP; 15,000 and more - 9.6 EER/3.0 COP
Incentive varies by SEER and EER level.
Incentive varies depending on whether the equipment is split or packaged and efficiency level.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
Table 21. HV AC incentive program design parameters.
Program Organization Eligible Application Payment Trade Ally
Project Types Procedure Process Services
Customer incentive is
based on the lesser of
Industrial energy savings, 50% of Retrofit and New CustomerEfficiencyIdaho Power project cost, or the one Check NoneConstruction.ncentive Program year simple payback
amount.
Washington &Customer
Idaho Energy Avista $0.04-$0.08 per annual Retrofit and New Check
kWh or 50% of total NoneEfficiencyCorporationproject cost Construction.
Incentives
Vendor
Rebates are reserved guidelines
PG&E, SoCal prior to equipment and
Express Efficiency Edison, SoCal Retrofit 1
installation. The Customer agreement
Check 2Gas, SDG&E application is Onlinesubmitted after
installation.equipment
database
VendorDealer Incentives Application is guidelines
Per unit incentive (see submitted by Distributor andUpstream Motors PG&E, SoCal
& Air Conditioning Edison, SoCal Table 20)distributor online with agreement
Program Gas, SDG&E Customer Incentives invoice. Customer Customer
Per unit incentive (see may submit for Checks Online
Table 20)incentive online.equipment
database
Nevada Power Pre-notification Quarterly
Company &required for vendor
Nevada Sure Bet Sierra Pacific Retrofit and New prescriptive projects Customer seminarsConstructionover $10,000 and Check 2Power Online vendor
Company custom projects over listing$7500 in incentives.
Various Utilities Pre-notification CustomerRetrofit and New required for projects Online vendorCool Choice in five North Check or
Eastern states Construction over $5000 in Bill Credit 2 listing
incentives.
$mart Equipment The application is CustomerNYSERDARetrofit 1 submitted after None 3ChoicesCheckinstallation.
Incentives for n\:i~" construction projects are addressed by a separate DSM program offering.
2 Customers can elect to have the incentive sent to a third party as designated on the application form.
3 Several HV AC distributor and contractor services, including education and training, are provided through another program offering.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
LIGHTING EQUIPMENT INCENTIVE PROGRAMS
Countless lighting equipment incentive programs exist around the country, which reflects both
the potential for available savings in lighting equipment and the proven and reliable nature of
high efficiency lighting technologies. Four high efficiency lighting equipment incentive programs
were investigated in detail. The programs reviewed included:
Idaho Prescriptive Lighting Program. Avista s prescriptive lighting program for
commercial and industrial customers in their Idaho service territory. Incentives are
available when pre-authorized for a prescribed amount that varies between $5 and $20 per
fixture. Incentives can be paid via a check to the customer or a credit against the utility
bill.
Express Efficiency. California s statewide prescriptive incentive program directed by the
California Public Utilities Commission and administered by the four IOUs in the state.
Nevada Sure Bet. Sierra Pacific Resource s energy efficiency program available to
customers of their two subsidiary IOU s in the state of Nevada.
Custom Efficiency. Xcel Energy s C&I DSM program offering within their Colorado
service territory.
All four programs shared some common traits, including:
Use of the Energy Policy Act of 1992 standards for fluorescent lamps and National
Appliance Energy Conservation Act standards of 1990 for ballasts in establishing
equipment baselines;
. A post -purchase customer application process requiring the following:
Customer information (name, address, building type, utility account number, etc.
Equipment information (fixture types and counts);
Customer signature, and;
Equipment invoice (except Custom Efficiency).
No dealer or distributor incentives.
Determination of estimated savings impacts for each of the programs were very similar as well
relying on calculated rather than measured values. Demand savings were estimated using the
difference in estimated fixture wattages. Estimates of annual energy savings were calculated by
multiplying the estimated demand savings by estimated annual operation hours, varying by space
type. Adjustments for peak coincident demand savings, transmission line losses, and the effects
of free-ridership were typically applied to propagate calculated savings at the customer meter
back to the generating plant.
Incentive levf h for the Express Efficiency and Nevada Sure Bet Prog--'lms vary on a $/fixture
basis. Nevada Sure Bet and the Idaho Prescriptive Lighting Program incentive levels are shown
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Review of Other Utility DSM Programs
in Table 22. Custom Efficiency incentives are paid on a $/kW saved basis and vary due to the
nature of the program, but average approximately $0.07 per kWh/yr saved.
Table 22. Nevada Sure Bet and Idaho Prescriptive Lighting Program lighting incentive levels.
Equipment Type
Idaho Pres. Lighting
Program
Incentive/Unit
Sure Bet
Incentive/Unit
Replace/Upgrade T-12 MB fixtures with TSfrS electronic ballast (per lamp)
Foot Fixtures
lamp to 4-lamp
lamp to 3-lamp
lamp to 2-lamp
Foot Fixtures
lamp to 3-lamp
lamp to 2-lamp
Foot Fixtures
lamp to 2-lamp
Foot Fixtures
lamp
lamp
Comoact Fluorescent
Screw-in CFLs
13 watts
14-26 watts
:=-=
27 watts
Hardwired CFLs
13 watts
14-26 watts
27 -65 watts
66-90 watts
:=-
90 watts
Exit SiQns
Incandescent Sign to new LED Exit Sign
Occuoancv Sensors roer sensor)
Wall Box
$10.
$12.
$15.
$15.
$16.
$18.00
$1 0.
$12.
$8.
$9.
$5.$4.
$20.
$15.
$30.
$15.
$5.
$5.
$5.
$1.
$2.
$2.
$5.
$5.
$5.
$5.
$5.
$9.
$11.
$12.
$18.
$22.
$20.$12.
not specified $8.00
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 4 Recommendations
Based on the current FinAnswer Express program design, Nexant recommends three minor
modifications before introducing the program within PacifiCorp s Idaho service territory.
1. To test the market acceptance and savings potential, Nexant recommends that prescriptive
incentives for VFDs installed on HV AC system fans and chilled water pumps
-::::
100 hp be
added to the program. For this new measure type, an incentive level of $80/hp is
recommended.
2. Incentives for red LED traffic signals be discontinued in recognition that this measure has
been accepted as current practice in the marketplace.
3. Minimum efficiency requirements for packaged and split-system unitary equipment
-::::65 000 Btu/h be increased to 15 SEER/12.5 EER to reflect the upcoming change in
federal minimum efficiency standards.
4. The 25 000 CFM size limitation on evaporative equipment be removed.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 5 Potential Savings Analysis
Below are preliminary estimates of the incremental incentive costs and savings that could be
realized if the FinAnswer Express Program is implemented in Idaho.
PREMIUM EFFICIENCY MOTORS
Table 23 shows the estimated program impacts for premium efficiency motors for the first two
years of the program. Estimated impacts are based on the estimates in Section 2 tempered with
results from the 2004 FinAnswer Express Program. The savings reflect a 3% annual shift in sales
volume from EP Act motors to NEMA Premium Efficiency motors and recommended incentives
in the first year and a 5 % increase in the second. Assumptions regarding the energy and demand
calculations are discussed in Section 2.1.4.
Table 23. Estimated increased net motor costs and savings impacts in Idaho. 1
Net Net Annual Net Peak
Year Program Incentives Customer Energy Demand
Participation Incremental Savings Savings
Costs 2 (kWh) 3 (kW)
Year 1 15 motors 632 $998 023
Year 2 24 motors 601 $14 537 904
1 Estimates are for a full year program period.
2 Customer costs represent the net values inclusive of free-ridership estimates, but do not include the
impacts of available incentives.
3 Energy savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005).
4 Demand savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005), and a coincident demand factor of 0.74 (PG&E 2001).
HIGH EFFICIENCY LIGHT COMMERCIAL HV AC EQUIPMENT
Table 24 shows the estimated program impacts for light commercial HV AC equipment for Years
1 and 2 in PacifiCorp s Idaho service territory. Table 25 lists some of the key assumptions used
in developing these savings estimates, while individual equipment savings estimates were taken
from Section 2.2.4.
'-'1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Potential Savings Analysis
Table 24. Estimated increased net HV AC costs and savings impacts in Idaho.
Increased Net Net Annual Net Peak
Year High-Incentives Customer Energy Demand
Efficiency Incremental Savings Savings
Sales Costs 2 (kWh) 3 (kW) 4
Unitary
Year 1 34 tons $ 1 700 $ 3,264 979
Year 2 69 tons $ 3,450 $ 6 624 987
Evaporative
Year 1 678 CFM $294 $ (3 680)127
Year 2 30,237 CFM $ 605 $ (7 581)322
VFDs
Year 1 160 hp $12 800 $31 027 115,680
Year 2 240 hp $19,200 $46 541 173 520
Total
Year 1 $ 14 794 $ 30,611 117 786
Year 2 $ 23,255 $ 45,584 I 177 829
1 Estimates are for a full year program period.
2 Customer costs represent the net values inclusive of free-ridership estimates, but do not include the
impacts of available incentives.
3 Energy savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005).
4 Demand savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005), and a coincident demand factor of 0.87 (PG&E 2001).
Table 25. HV AC equipment evaluation parameters.
Parameter Unitary Evaporative
Customer Incentive $50/ton $ 0.02/CFM
Customer Incremental Cost $1 OO/ton $ (0.26)/CFM
Peak Coincident Use Factor
Net-to-Gross Savings Ratio
LIGHTING EQUIPMENT
Table 26 shows the estimated program impacts for high efficiency lighting for Years 1 and 2.
Estimated impacts are based on Idaho electrical sales and FinAnswer Express lighting project
trends for PacifiCorp s Utah and Washington territory for 2001-2004.
'-'1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section Potential Savings Analysis
Table 26. Estimated increased net lighting costs and savings impacts in Idaho. 1
Increased
High Net Net Annual Net Peak
Customer Energy DemandYearEfficiencyIncentivesIncrementalSavingsSavingsSalesCosts 2 (kWh) 3 (kW) 4
($1 OOO'
Year 1 $457 $ 28 314 $93 952 210,185
Year 2 $ 1 985 $ 56,441 $187 287 418 987
1 Estimates are for a full year program period.
2 Customer costs represent the net values inclusive of free-ridership estimates, but do not include the
impacts of available incentives.
3 Energy savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005).
4 Demand savings reflect net impacts at the customer meter with an assumed net-to-gross ratio of 0.
(Express Efficiency Program Offering, DEER 2005), and a coincident demand factor of 0.70 (PG&E 2001).
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 6 References
ASHRAE, 2003. 2003 ASHRAE Applications Handbook. Chapter 36.
CEE, 2003. Program summaries for HECAC Initiative Participants.
h!!p:/ /www.ceel.org/resrc/updates/02-08hecac/program sums. pdf
CEE, 2003b. Incremental HV AC equipment costs.
http://www.cee1.org/com/hecac/hecac chart.pdf
Center for Energy and Environment, 1999. A Practical Guide to Commercial Air Conditioning
Rebates for Municipal Utilities.
DEER (Database for Energy Efficiency Resources) 2005. http://eega.cpuc.ca.gov/deer/
DOE/EIA 2002. 1999 Commercial Buildings Energy Consumption Survey.
http://www .eia.doe. gov / emeu/ cbecs/contents.html
EIA, 1994-2002. Monthly Electric Utility Sales and Revenue Data Form EIA-826.
http://www .eia.doe. gov /cneaf/electricity/page/eia826.html
ESource, 1997. Lighting Technology Atlas.
ESource, 2003. Incentivesfor Premium Efficiency Motors, The Role of Prescriptive Rebates in
the Post-EPAct Era. ER-03-, Tech.
PG&E (Pacific Gas & Electric Company), 2001. Workpapers for the 2001 Express Efficiency
Program.
PG&E (Pacific Gas & Electric Company), 2005. 2005 Express Efficiency Program Summary.
RTF (Regional Technical Forum), 2005. http://www.nwcounci1.org/energy/rtf/Default.htm
State of Washington, 2002. Washington Economic and Revenue Forecast
http://www.wa.gov/ofc/pubs/sep02pub.pdf
US Department of Commerce, 2001. Motors and Generators: 2001. MA335H(01)-
(,,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Section 7 Appendices
Presented in the following four appendices is information and supplemental materials supporting
this report. Specifically:
Appendix A Motor Survey Results. Summarizes the survey results from motorprofessionals.
Appendix B HV AC Survey Results. Summarizes the survey results from HV
professionals.
Appendix C - Lighting Survey Results. Summarizes the survey results from lighting
professionals.
Appendix D - Lighting Equipment Costs and Savings. Identifies the estimated savings
customer costs, and recommended incentive levels for prescriptive lighting equipment
retrofits and upgrades.
Appendix E PTAC/PTHP Equipment. Presents updated savings and customer cost data
associated with a revised minimum efficiency requirement for PT AC and PTHP
equipment.
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix A - Motor Survey Results
Listed below are the aggregated responses to the survey conducted for electric motors.
1. Company type (choose all that apply).
Percent of Respondents Reporting Role (multiple roles)
670/0 Manufacturer Rep.
170/0 Independent
830/0 Mfr Employed
330/0 Distributor
1000/0 Independent
00/0 Mfr owned
440/0 Repair/Service 00/0 Other
2. Approximately what percent of your business is derived strictly from motor sales?
Average: 54%Range: 8% to 100%
3. What is your service territory within Idaho?89% Statewide; 11 % Central Idaho
4. What motor manufacturers/brands do you represent?
Percent of respondents carrying manufacturers/brands:
Leeson:
Baldor:
WEG:
General Electric:
Reliance:
Siemens:
Lincoln:
US Motors:
AO Smith:
Brooks / Compton:
Lafert:
Emerson:
Fasco:
56%
44%
33%
33%
33%
22%
22%
22%
22%
11%
11%
11%
11%
5. Please list any analysis or software tools you use as part of the sales process to estimate
operating costs (energy, O&M) or potential ~Jvings associated with premium efficiency
motor.
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix Motor Survey Results
Percent of respondents reporting use of tools: (3 of 9 respondents did not reply)
Payback Analysis Charts:
Baldor Save Plus:
Motor Master:
Other / Various:
None:
22%
11%
11%
22%
11%
6. Do you identify opportunities and calculate energy savings for VFD retrofits.
Percent of respondents reporting:Yes 56%No: 44%
7. Do you offer services to identify opportunities for motor right -sizing? Is so, please
explain.
Percent of respondents reporting:Yes 78%No: 22%
Altitude, temperature, SF, HP, PF, Torque, and efficiency are considered
8. Do you have the capability to take 3-phase power measurements of existing motors.
Percent of respondents reporting:Yes 78%No: 22%
9. Please summarize your annual sales volume of motors (if possible, motors used in
commercial applications).
Average % of units that
Size Category meet or exceed
NEMA PE Standard
1 - 5 hp 16%
6 - 20 hp 160/0
21 - 50 hp 230/0
51 -100 hp 230/0
101 - 200 hp 220/0
""
Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix Motor Surve Results
10. Please characterize the driving factors for premium efficiency motor sales.
Reason for Equipment Sale Average Percentage
Equipment Failure 57.2 %
Planned Replacement 15.4 %
New Construction 21.4 %
Other 0 %
Total 1000/0
11. Please identify the key decision maker in premium efficiency motor purchases.
Key Decision Maker Percentage
Building Owner 57.7 %
A&E Firm 28.2 %
Contractor 10.2 %
Other 8 %
Total 1000
12. In your opinion, what are the key decision making criteria most customers employ to
select their new motor?
Percent of respondents reporting: (1 of 9 respondents did not reply)
Price:
Manufacturer / Brand:
Quality / Reliability:
Time / Availability:
Specifications:
Service:
89%
33%
33%
22%
11%
11%
'-'1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix Motor Survey Results
13. Please summarize the typical stocking practice for premium efficiency motors.
Average Percentage Percentage Sold from
Size Category Sold from Local Manufacturer
Inventory (0/0)Inventory (0/0)
1 - 5 hp 230 770/0
6 - 20 hp 220/0 780
21 - 50 hp 22%780
51 -100 hp 200 800
101 - 200 hp 140 860/0
14. Please characterize the typical sales patterns for premium efficiency motors.
(Response not summarized)
Date Equipment Planned New Other
of Sale Failure Replacement Construction /0)(0/0)(0/0)(0/0)
1 st Quarter (Jan-Mar)
2nd Quarter (Apr-Jun)
3rd Quarter (Jul-Sep)
th Quarter (Oct-Dee)
Total 1000/0 1000 1000/0 1000/0
15. Please rank the following market barriers to increased sales of premium efficiency motors
from 1 to 11 (1 equals largest barrier, 11 equals smallest barrier).
Average Rank
Score Barrier
First Cost
lack of Owner Familiarity with High Efficiency Equipment
lack of A&E and Contractor Familiarity with High Efficiency Equipment
Status Quo
Service Problems
low Incentives
long Paybacks
Limited Equipment Options
Single citation
given (rank=2)Other reason given: "ability to quickly process incentive
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix Motor Surv Results
16. Please rank the following resources in terms of ability to increase sales of premium
efficiency motors from 1 to 10 (1 equals most valuable resource, 10 equals least valuable
resource).
Average Rank Score
Single citation given
(rank =4)
Resource
Educational materials targeting end-use customers
Educational materials targeting contractors and other market players
Utility program marketing collateral
Utility-provided savings calculation tool
Streamlined application paperwork process
Prescriptive incentive levels for appropriate equipment
types/sizes/efficiencies
Utility Incentives for the end-user
Utility Incentives for the Equipment dealer/manufacturer representative
Other (please specify) "joint marketing partnership w/ PacifiCorp" - (rank
=4)
17. If you feel utility incentives are a key component to increasing sales of high efficiency
premium efficiency motor, please indicate the minimum level necessary to impart a
noticeable change (i.e. 10 - 15% increase) in the market place.
Average minimum simple payback for customer (range 1 to 5 years from 670/0 of
respondents)
Average minimum percentage of incremental customer cost
(10 % to 90 % as specified from 560/0 of respondents)
0 yrs
36 %
18. In your opinion, are customers generally aware of the motor incentives offered by Utah
Power? 100% of respondents answered No
19. For customers who are made* aware of the Utah Power motor incentive program, why do
some choose not to participate?
Percent of respondents reporting: (1 of 9 respondents did not reply)
Up front cost:
Lack of education / don t recognize benefits:
Not worth trouble / paperwork:
Time to Complete process:
44%
33%
22%
11%
* see response to question 18: respondents assumed to have made customers aware of program
""
Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix A Motor Survey Results
20. In your opinion, what could be done to increase the percentage of premium efficiency
motors sold into the Utah Power market?
Opinions Given:
a. Educate owners regarding benefits, actual energy cost of operating motors and
paybacks.
b. Enhance marketing of incentive program / involve the manufacturers
c. Provide direct rebates
d. Increase incentivese. Streamline process
f. PP to form partnerships with full service companies to reach customers at
decision point of motor replacement
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix B - HVAC Equipment Survey Results
Listed below are the aggregated responses to the survey conducted on light commercial HV
equipment.
1. Company type (multiple responses allowed)
Manufacturer Rep. Distributor
Independent Independent
Mfr. employed Mfr. owned
Repair/Service Other
2. Analysis or software tools used as part of the sales process to estimate operating costs (energy,
O&M) or potential savings associated with commercial cooling equipment. (number of
responses)
Manufacturer software package/savings calculator
Commercially available software package/savings calculator
Custom made software package/savings calculator
None
3. Reported annual sales volume of commercial cooling equipment.
Evaporative Unitary
Size Category
(# units)(# units)
% of sales that exceed listed
efficiency levels
-=::
65,000 Btu/h 300 13 SEER .::::5%
~ 65 000 Btu/h &100 550
: 11.0 EER .::::5%
-=:: 135 000 Btu/h 11AIPLV
~ 135,000 Btu/h &
265
10.8 EER .::::5%
-=:: 240 000 Btu/h 11.21PLV
~ 240,000 Btu/h 310
: 10.0 EER .::::5%10AIPLV
'-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix B HV AC Equipment Survey Results
4. Driving factors for commercial cooling equipment sales.
Reason for Equipment Sale Sales
Percentage
Equipment Failure
Planned Replacement
New Construction
Other
Total 1000
5. Key decision maker in commercial cooling equipment purchases.
Key Decision Maker Sales
Percentage
Building Owner
A&E Firm
Contractor
Other
Total 1 000/0
6. Key decision making criteria when purchasing new commercial cooling equipment. (number of
responses)
Contractor price
Value for building owner
Durability
EER
~1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix B HV AC Equipment Survey Results
7. Typical stocking practice for commercial cooling equipment.
Percentage Sold from Percentage Sold from
ManufacturerSize Category local Inventory Inventory(0/0)(0/0)
0:::000 Btu/h
~ 65,000 Btu/h &
0:::135 000 Btu/h
~ 135 000 Btu/h &
0:::240,000 Btu/h
~ 240 000 Btu/h
8. Typical sales patterns for commercial cooling equipment.
Date Equipment Planned New Other
of Sale Failure Replacement Construction
(%)
10)(0/0)/0)
1 st Quarter (Jan-Mar)
2nd Quarter (Apr-Jun)
3rd Quarter (Jul-Sep)
th Quarter (Oct-Dec)
Total 1 000/0 1000/0 1000
9. End-use customer incremental costs.
Minimum Incremental % Premium vs.
Size Category Efficiency levels Cost ($/ton)Standard
Efficiency
0:::000 Btu/h 13 SEER $83 15%
~ 65,000 Btu/h &11.0 EER $66 20%
0::: 135 000 Btu/h 11.4 /PL V
~ 135 000 Btu/h &10.8 EER $63 20%
0::: 240,000 Btu/h 11.2/PLV
~ 240 000 Btu/h 10.0 EER $50 20%10.4 /PL V
1.,,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix B HVAC Equipment Survey Results
10. Market barriers to increased sales of high efficiency commercial cooling equipment from 1 to 11
(1 equals largest barrier, 11 equals smallest barrier).
Median
Rank
4.4
8.4
Barrier
First Cost
Lack of Owner Familiarity with High Efficiency Equipment
Lack of A&E and Contractor Familiarity with High Efficiency Equipment
Status Quo
Service Problems
Low Incentives
Long Paybacks
Limited Cooling Hours
Limited Equipment Options
11. Please rank the following resources in terms of ability to increase sales of high efficiency
commercial cooling equipment from 1 to 10 (1 equals most valuable resource, 10 equals least
valuable resource).
Median
Rank
5.4
2.4
Resource
Educational materials targeting end-use customers
Educational materials targeting contractors and other market players
Utility program marketing collateral
Utility-provided savings calculation tool
Streamlined application paperwork process
Prescriptive incentive levels for appropriate equipment types/sizes/efficiencies
Utility Incentives
Equipment dealer/manufacturer representative incentives
12. Minimum equipment incentive level necessary to impart a noticeable change in the sale of high
efficiency cooling equipment (i.e. 10 - 15% increase) in the market place.
Minimum simple payback for customer (yrs)
Minimum percentage of incremental customer cost (%)
1.,,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix B HV AC ment Surve Results
13. Are commercial customers generally aware of the cooling equipment incentives offered by
PacifiCorp (number of responses)
Yes
14. What could be done to increase the percentage of high efficiency commercial cooling equipment
sold in the market? (number of responses)
Provide educational materials on the benefits of high efficiency cooling equipment
Provide utility incentives
Increased awareness of incentive program
Earlier and easier access to rebates
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix C - Lighting Equipment Survey Results
Listed below are the aggregated responses to the survey conducted on lighting equipment.
1. Company type (multiple responses allowed)
Distributor
Direct Sales
System Design
Contractor
Other
2. Please estimate the gross sales of commercial and industrial lighting projects your company was
involved with in Idaho during the past 12 months.
Project Type Direct Sales
($)
System Design
($)
Installation
($)
Retrofit/Tenant Improvement 515 000 18,555,000 520,000
,............,,.'"....".."""""".............,."'..."'.....,..................."""""""""""""......"..,..,."""""""""""","'"""""""",..,"'"'.."..,.,""""""""""""""""""",."""",.,..,....'"....,...."'......".."".".,"'"."""""""""",,"""".."""".."""""..""..".,."'.""""..""""""""""""""""."..
New Construction 424 000 17,525 000 095,000
Total 939 000 36,080,000 615 000
3. Please characterize the driving factors for commercial and industrial lighting equipment sales.
(sales weighted response)
Reason for Equipment Sale Percentage
Equipment Failure
..-..-
Planned System Upgrade 19%
Unsolicited Proposal 30%
Tenant Improvement (TI)14%
New Construction 27%
Total 100%
4. Please identify the key decision maker in lighting equipment purchases. (sales weighted
response)
Key Decision Maker Percentage
Building Owner 54%
A&E Firm/Lighting Designer 23%
Contractor 19%
Maintenance
Total 100%
(,1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix Lighting Eq ment Surv Results
5. In your opinion, what are the key decision making criteria when purchasing new lighting
equipment? (Top 6 responses in descending order)
First Cost
Aesthetics
Energy Savings
Warranty/Quality
Return on Investment
Payback
6. Please estimate the allocation of your lighting equipment sales across the following three general
categories. (sales weighted response)
Linear Fluorescent High Intensity Discharge Other
(%)(%)
(OJo)
T12 Mercury Vapor Incandescent 13%
.....,~
~w..,.
". .,_..,....,....,.
..., ..,-_._.._....._-~-, ~W-
~-~....
........~...._..w~..w~,~......
""~"""--"-""'-""-"._"'_""-"-"'--.""'-".._.,..-........._"..,........,.....,...~..~..
,..~,..,......~.....w....w.~.,~w...............
_,...,........,..,...~,~..__.~......~......~._.._.~-,
74%High Pressure Sodium 13%Halogen 37%
-_.__..
Enhanced" T8 10%Metal Halide 21%Screw-in CFL 11%
"'-"'-""
"""""""W""""""""-'--""'-'....."
"""""-"""""--"""""""""-"-""""" "" '"""-"-'--'" -'...... '.... ..- --, '.. ...-......--.-.- ....-....'""""""""'"",,'.""'-'"..,..,..,.,..,....""",""'..""""'-"""""""""""""'-""""'"....--...--.......-...---..-,...,.....
(incl.High Bay)Pulse Start MH 59%Hardwired CFL 40%
Total 100%Total 100%Total 100%
7. Please list any analysis or software tools you use as part of the sales process to estimate potential
O&M or energy cost savings associated with the installation of high efficiency lighting
equipment.
70% use custom developed Microsoft Excel Spreadsheets
12% do not use any software tools
18% use a variety of commercially available software packages
8. Please estimate what percentage of lighting projects are currently participating in one of Utah
Power s efficiency programs and receiving incentives. (sales weighted response)
Percent Participating in
Current Utility Programs
(%)
46%
10%
Project Type
RetrofitlTenant improvement
New construction
L-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix Lighting Eq ment Surv Results
9. For projects that are not participating in one of Utah Power s current programs, please indicate
why (check all that apply). (sales weighted response)
Reason for Not Participating
Unaware of utility incentive programs
Difficult application process
Limited availability of utility-eligible lighting technologies
Absence of incentives for lighting-only projects in new construction
Inadequate incentives
Fear of possible delay in project completion
Installation of ineligible equipment
Lack of capital
10. Please rank the following market barriers to increased sales of high efficiency lighting equipment
from 1 to 10 (1 equals largest barrier, 10 equals smallest barrier). (sales weighted response)
Rank Barrier
First cost
Market uncertainty
Lack of owner familiarity with high efficiency equipment
Lack of A&E and contractor familiarity with high efficiency equipment
Status quo
Low utility incentives
Long paybacks
Limited savings opportunities
Aesthetics
~1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix Lighting Equipment Survey Results
11. Please rank the following resources in terms of ability to increase sales of high efficiency
lighting equipment from 1 to 11 (1 equals most valuable resource, 11 equals least valuable
resource) .
Rank Resource
Educational materials targeting end-use customers
Educational materials targeting designers, contractors and other market players
Utility incentive program marketing collateral (i.e. case studies, program brochures, etc.
Utility-provided savings calculation tool
Technical seminars and training for lighting dealers and distributors
Additional utility and co-operative marketing efforts
Streamlined application process
Uniform incentive application process for retrofit and new construction projects
Customer incentives
Lighting equipment dealer/distributor incentives
12. If you feel utility incentives are a key component to increasing sales of high efficiency lighting
equipment, please indicate the minimum level necessary to impart a noticeable change in
consumer behavior.
39%
Minimum simple payback for customer (yrs)
and/or
Minimum percentage of incremental customer cost (%)
13. Which of the following two incentive mechanism do you prefer: 1) A program that provides
prescriptive incentive levels for a fixed assortment of high efficiency equipment, supplemented
with a custom track (where incentives are a function of the realized savings) for fixture types not
identified, or 2) one that prescribes all fixture wattages and run hours and pays incentives on a
$/kWh saved basis?
1 - 25%
2 - 75%
14. For the first incentive mechanism described above, please indicate which of the following
abbreviated general incentive table formats you prefer:
66%
Interior Fluorescent
Fixture Upgrade to
standard T8 lamps and
electronic ballasts (EB)
Existing TI2Iamp(s)
4' T8 Lamp (s)
8' T8 Lamp (s)
8' T8/HONHO Lamp(s)
$ X/lamp
$ XIlamp
$ XIlamp
$ X/lamp
$ XIlamp
$ XIlamp
'-'1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix Lighting Equipment Survey Results
33%
, -
1 or 2 T12 lamp(s) + 1 magnetic
, -
1 or 2 T8 lamps+ 1EBallast (MB)
Interior Fluorescent Fixture 3 or 4 T12Iamp(s) + MB(s)
, -
3 or 4 T8 lamps+ 1EBUpgrade to T8 lamps and
electronic ballasts (EB)
, -
3 or 4 T12lamps + MB(s)- 1 3 or 4 T8lamps +1EB
, -
3 or 4 T12/HO lamps + MB(s)- 1,3, or 4 T8/HO lamps +EB
maximum of 2)
Interior Fluorescent
' -
2 T12lamps + 1 MB
Delamping and Fixture
, -
3 T12lamps + 2 MB or 1-T8lamp + 1EBUpgrade
(Fixture removal is not
' -
4 T12lamps + 2 MB T8lamps + 1EB
eligible)
, -
4 T12 + 2 MB or 1-T8lamp + 1EB
15. Utah Power is considering offering additional incentives for Premium or Enhanced T8 fixtures.
Following is a proposed definition of these fixtures. Please provide any comments on the
applicability of this definition, or suggestions for alternative approaches.
Enhanced, or Premium, T8 fixtures are defined by an initial lamp ballast efficacy of
95 lumens per watt or greater, where the initial efficacy is calculated as follows:
Initial Fixture Efficacy Initial Lamp Lumens
* #
Lamps Ballast Factor
Ballast Input Watts
56% - No response
25% - Approved of proposed definition
19% - Suggested a lumen/ballast factor based definition
16. In your opinion, what could be done to increase the percentage of high efficiency lighting
equipment sold into the Utah Power market? (Top 6 responses in descending order)
Customer and contractor educational efforts
Increase available incentives
Provide financing for projects
Provide additional marketing materials
Nothing market and economy driven
Offer contractor incentives
4.-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
Appendix Lighting Eq ment Surve Results
17. Please estimate the additional gross sales that would participate in Utah Power s incentive
program each year if all of your suggested program changes listed above were incorporated.
Project Type Direct Sales
($)
System Design
($)
Installation
($)
RetrofitfTI 676 000 275 000 110 000
------
New Construction 402 000 3,425 000 530 000
Total 078,000 700,000 640 000
18. Please estimate the average purchase costs incurred by the end-use customer for the following
general lighting equipment. (Insufficient response rate)
Linear Fluorescent CFLs HID
Tl2 lamp ($/lamp)Hardwired 13W PSMH .c::::35W
,."."""""""""""..,""""""""""."""",."'."",.",.""".""""""""""""",.",.,......."......""""""""""""",.."".""..""."..,...."..,""""""""..........".,."""'","'""""""""""""""."",.,,,........",.. ,..,""......"....,.,.."..",.....",.""""....,.,"""""""""""""""...
Tl2 lamp ($/lamp)Hard wired 14-26W PSMH 36- 70W___m
lamp ($/lamp)Hardwired 27-65W PSMH 71-1O0W
.,...""""""",..",....".""""""""""".,.""...","""""""""""""""""""""""""..""",.....".."""""".."""".."""..""".....",......","..""""""""""""..,.....,."..."..""""""..""""",......",.............,.......",....."""....""..."..."""".".........."",....."........",......,.,..,.........""....""""""""""""""""""",....
lamp ($/lamp)Hard wired 66-90W PSMH 1O1-175W
---'--,---~---
Enhanced"lamp ($/lamp)Hard wired 90W PSMH 176-250W
.."""""""""""""..,..,""..""""""""""""...",..,...."".".,.",."."."""""""""""""""""""'...........,..."""""""""""""""..."."..........."......,....",.""""""""""....".",.""",..."""""""""""..""..""..,""",.""................",...............""......""..,.""""".",.".."""""".","""""..""""""",
Enhanced"lamp ($/lamp)Ave Install Cost ($/fix)PSMH 251-400W
lamp ($/lamp)HPS ~lOOW
""""."....."" """ "...." ""......"......."" "" ".." "" ".".." "" """""""".." "" "" """ """""" ".." "" ".." "..",.....",.".."'""'",""""""""""",,,,,"""""""............""""""""""""""""."",""..........."""..""",.."","".."".."""""""""""....","""""""""""".."""".."""""".."""""..""..""..""""",.."""""""".....".."......",""""
Tl2 lamp ($/ballast)HPS 1O1-250W
..-._-
Tl2 lamp ($/ballast)HPS 251-400W
"""""....""""""""""""""",..".........""""""""""""""""""""""""""'.."..",.."",.."""""".."""..""...."".....".."",........"""""'"""""""""""."",."."""""..""""""",,........."",."..............".."""""""""'"",,"'.....,,...."......""....""""""""""..""""
lamp ($/ballast)Ave Install ($/fix)'-_N
----~
____N
----------..---
'___N NN-
lamp ($/ballast)
""""""..".............. "...." """ """ ".."...."",.." .......""..." ".." "" ".." """" ""'" "..."....."""""" "......." "..",""""'""""""",.,,,........""""""""".."""""""".."'...".""""""""""""""""""""""""""""""""".."""""",""".......""""......"""....""""""""""""""",......."""""""""""""""
lamp Premium ($/ballast)Bi-Level Control
---------
lamp Premium ($/ballast)Tn-Level Control
"""""""""""""""""""'"""""""""""""""....."..,...."..........""""""""""""""""""""'",.."."..."""""""""""""""""""""""""""""""""....."",......,..."..."""""",".."".."""..""""",..""""""""""""""..""""""""""""""""""""""""""""""""""","".."",.."""""",
lamp ($/ballast)
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..-----.....""'.... "'."'. ""---"-"-"""'--""'-"-' ..--
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lamp ($/ballast)
...."...."""""............
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Average Installation Cost ($/fixture)
4.-1 Nexanr FinAnswer Express Market Potential Assessment for Idaho
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Appendix E - PTAC/PTHP Equipment
For consistency with updates suggested for commercial unitary equipment, Nexant reviewed
Packaged Terminal Air Conditioner and Heat Pump (PTAC and PTHP, respectively) equipment.
Based on this review, recommended changes to minimum efficiency levels and customer
incentives for PacifiCorp s DSM programs are presented here. Also included are updated
estimates of customer s incremental costs and available savings associated with high efficiency
PT AC and PTHP units. No significant impact on program incentives or realized savings are
expected, and as such, results presented here are not incorporated in the savings and cost
projections provided in the main body of this report.
Equipment Efficiency Levels
Suggested minimum equipment efficiency levels for PT AC and PTHP equipment are presented
in the following table. Minimum cooling EER values are based on a 7.5% increase over the
ASHRAE 90.1999 PT AC minimum values for new construction. Minimum heating COP
values are based on a 7.5% increase over the ASHRAE 90.1999 PTHP minimum values for
new construction.
Recommended minimum equipment efficiency levels.
Minimum Minimum
Equipment Size Cooling EER Heating COP
(PTAC & PTHP)(PTH P)
-:::8 000 Btu/h 11.
000 and -:::10 500 Btu/h 11.4
500 and -:::13,500 Btu/h 10.
500 Btu/h 10.
Equipment Savings
Estimated energy and demand savings for qualifying PT AC and PTHP equipment are presented
inthe following table. These estimates were derived from an hourly analysis of a typical hotel
modeled in DOE-2. The simulation was run using weather data for Salt Lake City, Utah. Due to
similar weather patterns and the small magnitude of savings, identified values are expected to be
acceptable for use throughout PacifiCorp s Idaho service territory as well.
A PT AC unit with electric resistance heat that met ASHRAE 90.1999 minimum equipment
efficiency levels for new construction was modeled as the baseline equipment. The high
efficiency PTAC unit also had electric resistance heat and an EER rating 7.5% above the
ASHRAE minimum for new construction. The high efficiency PTHP had the same cooling EER
rating and COP rating 7.5% above the ASHRAE minimum for new construction.
'-..,
Nexanr FinAnswer Express Market Potential Assessment for Idaho
endix E PT AC/PTHP Equipment
Estimated average energy and demand savings.
Net Peak Demand Net Annual
Equipment Type Savings Energy Savings
(kW/unit)(kW/unit)
High efficiency PT
High efficiency PTHP 890
1 Savings reflect net impacts at the customer meter with an assumed net-to-gross
ratio of 0.95 and a coincident demand factor of 0.77 (PG&E 2001).
Customer Incremental Costs
Based on a review of PT AC and PTHP equipment from four major manufacturers, the average
incremental customer cost to purchase a qualifying unit is $50 for PT AC equipment and $150 for
PTHP equipment. These incremental costs are in comparison to a PT AC unit that complies with
ASHRAE 90.1999 minimum equipment efficiency levels for new construction and do not
include the impacts of utility incentives.
Customer Incentive Levels
Nexant recommends that customer incentive levels be set at $50 per ton for all qualifying
equipment.
"'"
Nexanr FinAnswer Express Market Potential Assessment for Idaho
Submitted To:
AC IF CORP
Energy FinAnswerCID
Market Assessment
for
PacifiCorp s Idaho
Service Territory
Preliminary Findings
Submitted By:
NeKanr
September 17, 2004
(revised May 25 2005)
Contents
Section Page
EXECUTIVE SUMMARY........................................................................................................................................
ECTI 0 N 1 INTRODUCTION .......................
.................... ........................ .................... ........ ....................... ........
SECTION 2 UPPER BOUNDARY OF POTENTIAL ENERGY SAVINGS .....................................................
SECTION 3 SAVINGS ADJUSTMENT FOR ID MARKET CHARACTERISTICS.......................................
SECTION 4 EXTRAPOLATION OF FINANSWER PERFORMANCE IN W A AND UT TO ID
.................
4.1 W A AND UT FIN ANSWER PROGRAM REVIEW ................................................................................
ESTIMATED SAVINGS POTENTIAL AND ASSOCIATED COSTS ....................................................
SECTION 5 RECOMMENDATIONS AND NEXT STEPS...............................................................................
t-1NextlnT California Energy FinAnswer Market Assessment - Preliminary Findings
Executive Summary
In an effort to increase the number of comprehensive energy efficiency projects undertaken by
commercial, industrial, and agricultural end-use customers within PacifiCorp s Idaho service
territory, potential changes in the incentive delivery mechanism of the Energy FinAnswer
(FinAnswer) program are being evaluated. Specially, Nexant, Inc. has completed preliminary
steps to assess the savings potential associated with adopting the cash incentive structure used by
the FinAnswer program within PacifiCorp s Washington and Utah service territories.
These preliminary results, arrived at through a progressive three-step approach to assessing
market potential from a top-down perspective, indicate that a revision in the incentive structure
could result in energy savings totaling approximately 0.75% of total annual non-residential load
within three years. Total non-discounted costs to PacifiCorp, including program incentives and
administration costs, are expected to be $0.25/kWh of realized energy savings. Table i
summarizes preliminary savings and cost estimates associated with this programmatic change.
Table i. Estimated FinAnswer Program Performance in ID 1,
r;rj~~gy ..
~~yinS~.
MWhlr
. . .
850
560
940
350Total
$428
$1 ,284
605
317
$207
$630
$755
592
Year 1
Year 2
Year 3
Savings estimates are for a full year program period.
Measure costs represent the net values adjusted for an estimated net to gross ratio of 0., but do not include the
impacts of available incentives (Database for Energy Efficiency Resources, All Other Non-Residential Programs category,
www.rtf.nwppc.org/deer2005/).
Energy and demand savings reflect net impacts at the customer meter based on an estimated net to gross savings ratio
of 0.80 (Database for Energy Efficiency Resources, All Other Non-Residential Programs category,
www.rtf.nwppc.org/deer2005/).
Prior to proceeding with the final steps of the market assessment that will seek to update these
results using a bottom-up market approach, Nexant recommends that the potential cost-
effectiveness of the program be evaluated using the range of programmatic costs presented in
this report. Marginal cost effectiveness results may indicate an increased level of importance on
the feedback obtained by contacting vendors and customers in the local market. Conversely,
favorable cost-effectiveness results may allow for a less focused market-based effort.
"1 Nextlnr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section 1 Introduction
This preliminary report summarizes work completed by Nexant, Inc. to date in conducting a
market assessment of the savings potential associated with modifying the incentive structure of
PacifiCorp s Energy FinAnswer (FinAnswer) program in their Idaho (ID) service territory.
Specifically, the assessment has focused on the electric savings potential by adopting the
FinAnswer incentive structure currently available in PacifiCorp s Washington (W A) and Utah
(UT) service territories. No other changes in the program delivery model, including the
availability of detailed energy studies at no cost to the customer, have been evaluated.
The W A and UT FinAnswer programs offer customers a first-year savings incentive of
$0. 12/kWh plus $50 per average first-year monthly on-peak kW reduction. This incentive
structure has generated a higher level of program participation than the corresponding low-cost
financing mechanism currently available in ID.
As illustrated below in Figure 1-, the first three steps of these market assessment activities have
been completed and are reported in this document. Each of these steps has sought to build upon
the previous results and increase the accuracy of the savings estimates. Steps 4 and 5 would
provide further refined market information based on a bottom-up market approach including
stakeholder interviews, surveys, and scoping visits.
Step 1: Establish an upper savings boundary for
PacifiCorp s FinAnswer program in ID
Step 2: Adjust savings estimates for regional
factors in PacifiCorps ID service territory
Step 3: Compare ID savings estimates with
FinAnswer s performance in WA and UT
Sufficient Information Obtained
No Further Assessment
Additional Accuracy Warranted,
Proceed With Steps 4 and 5
Step 4: Conduct market surveys with
regional market stakeholders in I
Step 5: Interview key customers in ID and
conduct a series of initial scoping visits
Figure 1-1. Approach of ID FinAnswer Market Assessment
The remainder of this document is structured as follows:
Section 2 provides an estimate of the upper savings boundary (i., achievable annual MWh
savings) for a revised FinAnswer program in ID;
L-1NextlnT Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section Introduction
Section 3 incorporates regional characteristics of the ID market, as well as the experience of
other relevant utilities, into a revised upper savings boundary estimate;
Section 4 uses the performance of the FinAnswer programs in W A and UT to estimate a final
preliminary savings estimate for PacifiCorp' s ID service territory; and
Section 5 outlines recommended next steps.
~1 Nexanr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section 2 Upper Boundary of Potential Energy Savings
The FinAnswer program targets energy savings from non-residential electric customers that
implement energy efficiency measures as part of retrofit or new construction projects. Total
commercial and industrial (C&I) electricity consumption in PacifiCorp s ID service territory was
157 364 MWh for the 12-month period ending March 2003.Table 2-1 lists a range of
potential annual savings estimates for energy efficiency programs taken from various recent
market potential studies and discussions with utility company representatives.
Table 2-1. Summary of Recent Market Assessment Results
. ... .
IVI~t~~~~~$~~~ij1~~t~at1~ .
. .. ... .
.. Q~~PI1~~iQI)~..Wit~..~~.~Ft~~P....gtiJi~y.
.. ... .......
.Repres~ijt~tiY~$
.. ....... .
ACEEE review of regional U.S. energy
efficiency market assessments (i) - 2004
PG&E funded industrial energy
efficiency market study (ii) - 2001
Hewlett Foundation study on the energy
efficiency potential in CA (Hi) - 2002
Electric utility, California (iv) - 2004
.. .. ..'
~Vg~~~VJng~~~~t
. .
(o/pqft9t~lq~~) .
..... .
Electric utility, California (vi) - 2004
Annual economic potential for C&I
and residential users
Actual savings from industrial
rebate program, 1995 -1999
Annual economic potential for C&I
and residential users.
C&I assessment but commercial
end-users provide bulk of savings
Reflects experience in C&I sector
over the last 15-20 years
Based on utility C&I program
results and recent market studies.
0.4%
5% to 2%
Electric utility, Northeast U.S. (v)- 2004 5% to 1%
Notes: (i) Technical, Economic, and Achievable Potential for Energy Efficiency in the U.S., Nadel, Shipley, and Elliott, ACEEE;
(ii) CA Industrial Energy Efficiency Market Characterization Study, XENERGY, 2001; (iii) California s Secret Energy Surplus,
2002; (iv), (v), and (vi) all data based on discussions with utility representatives in September 2004.
Savings estimates listed in Table 2-1 cover studies that have been completed in over ten different
states ranging from the Northeastern U.S. to the Pacific Northwest. Despite the variation of end-
use sectors and geographic areas covered in Table 2-, the savings estimates in these studies
range between a relatively narrow band of 0.5% to 2% of annual consumption. Nexant conducted
interviews with representatives of utilities operating energy efficiency incentive programs to
confinn the validity of these market assessments. These discussions, which focused on the
perfonnance of C&I programs, confinn that savings levels between % and 2% of total annual
C&I electricity consumption are achievable.
To establish an upper savings boundary estimate for a revised FinAnswer program in ID, an
average value within these estimates of 1.5% of annual consumption was utilized. This
corresponds to a savings estimate of approximately 17 400 MWh/yr (1.5% X 1 157 364 MWh)
in PacifiCorp s ID service territory.
Source: Usage data provided by PacifiCorp in an email dated August 10 2004. This value does not include
~;. ~cial contracts customers since they are not eligible to participate in :_c FinAnswer program.
(,,1 Nextlnr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section 3 Savings Adjustment for ID Market Characteristics
Two main factors contribute to a recommended downward adjustment of the 1.5% upper savings
boundary estimate for PacifiCorp ' s ID market established in the previous section. First, energy
prices are lower in PacifiCorp s ID service territory compared to those offered by utilities
operating in near-by states, reducing the strength of economic drivers to implement energy
efficiency measures. Figure 3-1 illustrates that PacifiCorp s industrial and commercial rates in
ID are roughly half of comparable average electricity rates in the Pacific zone and a quarter of
those offered in Mountain zone states (and well below average listed for all other U.
geographic zones).
KEY:
Census Division
Commerciall Industrial
Source: EIA average electricity prices (in cents per kWh) for 2003 for the Continental u.S.
Figure 3.1. PacifiCorp 10 C&I Prices (cents per kWh) versus the Continental U.
Secondly, PacifiCorp s ID service territory has a predominantly rural demographic with no
major urban centers. PacifiCorp s ID service territory is second smallest (after CA) of the six
Western states that it covers, accounting for slightly over six percent of its annual electricity
sales and total number of customers.2 In general, the size and customer make-up of the ID market
indicates that a more limited potential for achieving energy savings exists than in other parts of
the state or country. Figure 3-2 illustrates the relative size of the ID service territory-in terms of
total number of customers (residential and C&I) and annual C&I electricity sales--compared to
PacifiCorp' other service territories.
Pc :lfiCorp Form lO-Kfor the fiscal year ended March 31, 2004.
'-'1 NexanT Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section Introduction
000
500
..........-...
000
500
000
500
,-...
~ 11 000
~ 10 500
= 10 000~ 9,500
"= 9 000
~ 8 500
.; 8 000
00 7 500
....
~ 7 000
:s 6,500~ 6,000~ 5,500
.....
~ 5 000
~ 4 500
~ 4 000~ 3,500
000
500
000
500
000
500
.......................................................................................................................................................................................................................
650
LEGEND
.. Annual MWh
m Customers
700
600
550
,-...
500 ?
450 :;-
'"'
400 ~
350 ~
'"'
300 ~
250 Z
....
200 E--
150
100
UT OR WY WA 10
Notes: Customer data from PacifiCorp s 10-k report for the fiscal year ended March 31 2004. MWh sales data from PacifiCorp s Table, 2003.
Figure 3-2. Comparison of PacifiCorp Service Territories in the Western U.
To account for these lower energy prices and the overall composition ofPacifiCorp s service
territory in ID, the 1.5% upper savings boundary estimate was lowered to approximately %. In
terms of potential energy savings, the application of this adjusted savings estimate translates into
a savings of approximately 11 600 MWh/yr (1% X 1 157 364 MWh) in PacifiCorp s ID service
territory .
t,1NextlnT Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section 4 Extrapolation of FinAnswer Performance in WA and UT to ID
This section presents revised savings estimates and the costs associated with the implementation
of a revised FinAnswer program in ID based on the results of Step 3 of the market assessment
activities (see Figure 1-1). Specifically, further refinements have been made to the savings
estimates from Sections 2 and 3 by extrapolating the historical perfonnance of the FinAnswer
program in WA and UT to PacifiCorp s ID market.
1 WA AND UT FINANSWER PROGRAM REVIEW
In W A and UT, the FinAnswer program has gained momentum in the marketplace, exhibited by
a steady increase in annual electricity savings. Table 4-1 lists key program results for both states
during the period of 200 1 to 2003.
Table 4-1. FinAnswer Program Performance in WA and UT*
.. .... ... ....... ................ ....... .... ................... ... . .... ... .... ............ ...... ...... . .. .
~r9$~grt~~g~
.. ..........
CI~I~$J~
.......... ...., , ,.(?~()~$~~#~(.. ,...
P~~~q~$~~~pjJ~.
..'....'.........
kW.
..'.'.'.....'...
Washin ton
2001
2002
2003
Utah
2001
2002
2003
539
303
21 ,726
22%
58%
04%
375
140
689
000
638
24,412
01%
05%
20%
214
655
090
*Note: Based on FinAnswer program perfonnance data for 2001 -2003 provided by PacifiCorp.
As can been seen from Table 4-, savings in PacifiCorp s WA service territory as a percentage
of total C&I load are larger than in UT by a factor of five. This is partially attributable to
momentum in the W A energy efficiency marketplace prior to the launch of the FinAnswer
program (where such market activity was effectively non-existent in UT). In addition, the fact
that the C&I load in W A is approximately one-sixth that in UT may contribute to the variation
smaller markets can respond more quickly to utility programs (less customers, more interaction
among customers and utility, etc.
PacifiCorp s cost of achieving energy savings from FinAnswer are associated with the costs to
provide the energy analysis services and implementation incentives of $0.12/kWh plus an
average monthly on-peak kW reduction of $50/kW for first year savings. Cash incentives
however, are capped at 50% of the eligible energy efficiency measure cost. Based on a review of
2002 FinAnswer evaluation reports, the total average program costs for W A and UT (in $ per
realized annual gross energy savings) were as follows:
Gross measure Cost: $0.23/kWh
Incentives: $0.09/kWh
Other Deferred Costs: $0.16/kWh.
PacifiCorp Energy FinAnswer 2002 Utah and Washington Progr, '1 Evaluations. Quantec LLc. August 2004.
'-'1 Nextlnr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section Extrapolation of FinAnswer Performance in WA and UT to
In terms of direct costs to PacifiCorp, the total average estimated cost per unit of realized gross
energy savings from the FinAnswer program in W A and UT is $0.25/kWh.
2 ESTIMATED SAVINGS POTENTIAL AND ASSOCIATED COSTS
As the size and customer mix ofPacifiCorp s W A service territory (in comparison to UT) more
closely approximates the area covered by PacifiCorp in ID, historical program activity in W A
will be relied on more heavily to predict potential outcomes in ID. Specifically, the 1% savings
of total annual C&I consumption in W A is considered to be a more reasonable estimate for
PacifiCorp s market in ID and consistent with findings presented in Section 2 of this report.
However, to reflect that the ID energy services market (i., presence of ESCOs and high
efficiency equipment vendors), while beginning to become more active, is still less developed
then within PacifiCorp s W A service territory, the gross estimate has been revised downward to
75%. The application of this assumed 0.75% savings estimate equates to an estimated annual
reduction of approximately 8 700 MWh (0.75% X 1 157 364 MWh) in PacifiCorp s ID service
territory.
Further, the % annual savings level for the W A FinAnswer program was achieved over a three-
year period. During this initial period, the level of annual savings increased significantly between
Years 1 and 2 as the program gained more traction. A similar period (path) of savings ramp-up
should be expected in ID. Figure 4-1 depicts a potential scenario in which the 0.75% annual level
of estimated gross energy savings from a revised FinAnswer program in ID are realized over an
initial three-year period as follows: 0.20% in Year 1 60% in Year 2, and 0.75% in Year 3.
500
000
500
000
500
---
~ 7 000
~ 6,500
:;- 6,000
QI)
.~ 5,500
~ 5 000
S 4 500
"0 4 000Q,I
....
e 3 500
~ 3 000
500
000
500
000
500
80%
~\~~'t'
~~ to'li-
.,.
'i-~~
~",.
~'t'
75%
70%
65%
J.~
~::~
f;J
" ~
rt.
,\~e
60% ~
55% ~
50% 8
....
0.45% ~
0.40% ~
35% ::
30%
?!-
25% :
QI)
20% .
15%
10%
05%
00%
Year End 1 Year End 2 Year End 3
Figure 4-1. Potential Ramp-up of GrosS" \nnual FinAnswer Savings in ID
"1 NextJnT Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section Extrapolation of FinAnswer Performance in WA and UT to ID
Average measure, incentive, and other deferred program costs taken from the 2002 Evaluation
reports of the W A and UT FinAnswer programs have been used to estimate corresponding costs
in ID.4 Table 4-2 summarizes the predicted costs and savings associated with a modified
FinAnswer incentive structure in ID. Cost data contained in Table 4-2 is based on average costs
for the W A and UT program. Due to the wide variation in these cost metrics between the two
service territories, Tables 4-3 and 4-4 are also included to establish estimated low and high-cost
boundaries corresponding to the same estimated savings assumptions.
Table 4-2. Estimated FinAnswer Program Performance in ID 1 ,
$428
284
605
$3,317
$207
$630
$755
592
Year 1
Year 2
Year 3
Total
Savings estimates are for a full year program period.
Measure costs represent the net values adjusted for an estimated net to gross ratio of 0., but do not include the
impacts of available incentives (Database for Energy Efficiency Resources, All Other Non-Residential Programs category,
www.rtf.nwppc.org/deer2005/).
Energy and demand savings reflect net impacts at the customer meter based on an estimated net to gross savings ratio
of 0.80 (Database for Energy Efficiency Resources, All Other Non-Residential Programs category,
www.rtf.nwppc.org/deer2005/).
Table 4-3. Low Cost Implementation Scenario
Year 1
Year 2
$332
$996
$1 ,246
574
$163
$490
$612
265
Year 3
Subtotal
1 Measure costs represent the net values adjusted for an estimated net to
gross ratio of 0.80, but do not include the impacts of available incentives
(Database for Energy Efficiency Resources, All Other Non-Residential
Programs category, www.rtf.nwppc.org/deer2005/).
Other deferred costs include training, administrative support, advertising, EEM inspections, ongoing evaluation
modeling! design! contract, and program management.
Tables 4-3 and 4-4 utilize the lowest or highest cost figure that is listed in the 2002 program evaluation reports
for W A and UT (e., the low cost scenario uses the incentive cost from UT ($0.07/kWh) rather than W A
($O.Il/kWh).
~1 NeJltlnr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section Extrapolation of FinAnswer Performance in WA and UT to 10
Table 4.4. High Cost Implementation Scenario
Year 1
Year 2
Year 3
Subtotal
$250
$750
$938
938
$550
651
063
265
1 Measure costs represent the net values adjusted for an estimated net to
gross ratio of 0., but do not include the impacts of available incentives
(Database for Energy Efficiency Resources, All Other Non-Residential
Programs category, www.rtf.nwppc.org/deer2005/).
'-'1 NextlnT Idaho Energy FinAnswer Market Assessment - Preliminary Findings
Section 5 Recommendations and Next Steps
Based on the success of the FinAnswer program within PacifiCorp' s UT and W A service
territories, proceeding with the revision to the incentive delivery mechanism within the Idaho
market appears to be justified at this stage of the market assessment. However, prior to making
the determination to move forward with steps 4 and 5 of the market assessment (see Figure 1-1),
Nexant recommends that PacifiCorp complete an analysis of the cost-effectiveness of the revised
program. Specially, the sensitivity of the results to the low and high-cost implementation
scenarios in Section 4 will help dictate the appropriate level of effort for steps 4 and 5. Marginal
cost effectiveness results may indicate an increased level of importance on the feedback obtained
by contacting vendors and customers in the local market. Conversely, favorable cost-
effectiveness results may allow for a less focused market-based effort.
"1 Nextlnr Idaho Energy FinAnswer Market Assessment - Preliminary Findings
REVIEW AND DEVELOPMENT OF
UTAH POWER'S IRRIGATION PROGRAM
IN IDAHO
Presented to
. UTAH POWER
Submitted By:
Fazio Engineering
November 17 , 2004
Revised August 31 2005
CONTACTS & PREPARATION
Pacific Power contact:
The program manager is
Don Jones, Jr
825 NE Multnomah
Suite 300
Portland, OR 97232
Phone: [phone]
Fax: [phone]
Email: Don.Jones JR~pacificorp.com
Energy Consultant contact:
This report prepared by
John A Fazio
Fazio Engineering
O. Box 246
Milton-Freewater, OR 97862
Phone: [phone]
Fax: [phone]
Email: fazio~bmi.net
Idaho Irrigation Program Review
Table of Contents
Executive Summary .................................................................................................
Demographics of Idaho Irrigation Accounts.............................................................. 2
Data Collected ..................................................................................................
Data Within Service Territory ............................................................................
Historical Energy Usage....................................................................................
Key Market Players........................................................................................... 5
2.4.Local Irrigation Suppliers............................................................................ 5
Federal Contacts........................................................................................
State Contacts..................................................................... ......................
2.4.County Extension Contacts: .......................................................................
2.4.Soil and Water Conservation Districts: .......................................................
Water and Groundwater Districts: ..............................................................
Review of Irrigation Program Designs.................................................. ....................
Recommended Program Design ..............................................................................
Nozzle Exchange ..............................................................................................
Primary Assumptions for Nozzles in the Nozzle Exchange portion of the
program ..................................................................................................................
Primary Assumptions for Gaskets and Drains in the Nozzle Exchange
portion of the program..............................................................................................
Implementation ........................................................................................
Pump Screening & Water Management Consultation .....................................
Primary Assumptions ............................................................................... 10
Implementation ........................................................................................
Pump Testing..................................................................................................
Primary Assumptions
...............................................................................
Implementation ........................................................................................
Deep Well Turbines .................................................................................
4.4 Center Pivot Equipment ..................................................................................
4.4.Sprinkler Pressure Regulator Replacement ............................................. 12
4.4.Low Pressure Drain Replacement............................................................ 13
4.4.Qualified Sprinkler Package Replacement...............................................
4.4.4 Dual Sprinkler Packages (Normal Flow and Lower Flow)......................... 14
System Re-designs and Major Replacements.................................................
Estimated Program Savings and Costs..................................................................
Idaho Irrigation Program Review
Appendix A: Idaho Irrigation Accounts by City
Appendix B: County Demographics of Idaho Irrigation Customers
Appendix C: Printouts of Spreadsheet Calculations
Appendix D: Summary of Idaho Irrigation Efficiency Program
Idaho Irrigation Program Review
REVIEW AND DEVELOPMENT OF
UTAH POWER'S IRRIGATION PROGRAM IN IDAHO
Aug ust 31 , 2005
EXECUTIVE SUMMARY
This report is prepared in support of a proposed irrigation efficiency program for Utah
Power customers in Idaho. Pending approvals, Utah Power plans to offer
their Idaho irrigation customers a comprehensive irrigation efficiency program to be
offered in addition to an incentive Energy FinAnswer/ FinAnswer Express suite of
programs in Idaho and the current Idaho load control program offered through Schedule
72. The main goals of this report are to:
Summarize the demographics of Utah Power s Idaho irrigation accounts and identify
key irrigation market actors.
Review program designs already in the market and/or provide recommendations for
a better alternative design from the standpoint of our Idaho irrigation accounts.
Using the recommended assumptions , estimate program savings and costs.
Based on field observations, discussions with key market stakeholders and potential
contractors who responded to the RFP, the currently proposed irrigation efficiency
program four main components.
1. A nozzle exchange program targeting hand lines, wheel lines and solid set
sprinkler systems. Exchange of pipe gaskets and low pressure drains are also
included in this program component.
2. An on-site pump and system screening that also provides an irrigation water
management consultation.
3. A pump testing and system evaluation component
4. A center pivot equipment replacement component with prescriptive incentives.
Items considered for replacement include sprinkler pressure regulators, pivot low
pressure drains and qualifying sprinkler packages
The following table summarizes the irrigation program results for Idaho using current
assumptions.
Idaho Irrigation Program Review
Summary - Potential Irrigation Energy Efficiency Impacts from a multi-year Idaho
program
Program Customer Annual Savings
Program Item Incentives Incremental Costs (kWh/yr)
Nozzle ExchanQe 100 707 086 755
Gasket ExchanQe 246 22,466 894 993
Drain ExchanQe 171 202 827 554 696
Pump Screening/Irrigation
Management 125,200 875 200
Pump Testing
Repair/Replacement 141 000 250 351 000
System
Redesign/Modification 88,125 60,000 702 000
Pivot Sprinkler Regulator
Replacement 103,914 43,297 957,047
Pivot Low Pressure Drain
Replacement 380 061 492 270
Replacement Sprinkler
Packages 122,400 $ 397 120 1,467 712
Dual Sprinkler Packages 20,000 000 269,800
Total $894 567.$641 728.651,473
Summary Table Notes:
Nozzle savings adjusted by 67% combined net-to-gross and savings realization ratio.
Nozzle costs not adjusted. Pump checks water management and pivot measures were
adjusted by 50% combined net-to-gross and savings realization ratio. Costs were not
adjusted. Incentives include service incentives such as pump testing. In addition, cost
effectiveness analysis applies net to gross ratio of. 75 on all savings and costs except
those resulting from Nozzle Exchange components. Savings in the table represent
savings delivered over a 2 year period from November 2005 through December 2007.
DEMOGRAPHICS OF IDAHO IRRIGATION ACCOUNTS
Data Collected
Utah Power provided a map of their Idaho service territory and the number of customers
and total kWh/yr by rate schedule. Additionally, Utah Power provided a list of meters for
irrigation accounts on rate schedule 10 in Idaho. This was used to estimate the number
of irrigation services by city. This customer break down by city is included in Appendix
A. As is typical with agricultural accounts, customers usually receive bills at locations
other than the service address. This data was sorted by city and state with about half of
locations outside Idaho grouped at the end of the list.
Idaho Irrigation Program Review
Figure 1 shows the service territory within Idaho.
Figure 1: Idaho Service Territory
Data was obtained from the 2002 Census of Agriculture for select counties in Idaho.
Primary data included are the number of irrigated farms; total irrigated acres; irrigated
pasture; potatoes; forage, hay and haylage; vegetable; and cattle and calves.
Initial discussions with local county agents in Franklin and Caribou counties lead to
contacting the agricultural statistics group of the agricultural census in Boise. Summary
of the 1998 statewide irrigation data is shown in Table 1. The latest Farm and Ranch
Irrigation Survey is not yet available.
Idaho Irrigation Program Review
Table 1: Statewide Irrigated Acres by Method
Irrigated
Irrigation Method # Farms Acres % of Total
Center PivoULinears 652 043,571 33%
Side Roll 507 575 875 18%
Hand Move 4,482 501 950 16%
Solid Set 438 61 ,746
Traveler/Big Gun 664
Gravity 994 991 613 31%
Drip 208 083
Totals 336 179 502
The data in Table 1 was used to estimate the number of irrigation systems in each
county. Based on conversations with National Resource Conservation Service (NRCS)
in Franklin County, many of the counties in southeast Idaho are primarily hand line and
wheel lines with small amounts of ground water. Additionally, these southeast counties
have short seasons growing primarily alfalfa and small grains. Counties located on the
Snake River plain are primarily center pivots. Similarly, Idaho Department of Water and
Power (IDWR) indicated that as much as 900/0 of the irrigation systems are center pivots
for areas located near Idaho Falls and Rexburg.
Data Within Service Territory
Utah Power s service territory covers many counties in Idaho. Appendix B estimates
crop acreage and irrigation method by county. In many cases only portions of a county
were within Utah Power s service territory. In these cases the amount of irrigated acres
was estimated as a percent of the county total. Percentages for each irrigation method
within a county were taken from the census statewide data and local estimates when
available. Table 2 summarizes the census data for the Idaho counties that are part of
Utah Power s service territory.
Table 2: 2002 Census of Agriculture Summary Data
Total
5,479
1 ,350 807
160 355
205 978
533 776
574
101
Estimated in
Service Territo
069
196 978
19,875
933
238
Using the estimated irrigated acres per county served by Utah Power, the irrigated acres
per irrigation method were estimated. The irrigation methods or systems considered
were center pivots, wheel lines , hand lines, solid set, big guns, gravity and drip. Using
standard acreages for each irrigation method, the number of systems was estimated for
each county. Table 3 shows the estimated irrigation methods within the service territory,
associated acres and number of systems.
Idaho Irrigation Program Review
Table 3: Estimated Irrigation Methods Inside Service Territory
Method Total Acres Acres/Method Total Systems
Center Pivot 58,450 120 487
Side Roll 677 26.338
Hand Move 823 541
Solid Set 825 191
Liner/Biq Gun 227
Gravity 980 120 566
Drip
Historical Energy Usage
The annual energy usage for all the Idaho irrigation customers is shown in Table 4. This
data was provided by Utah Power and represents a twelve-month period ending March
2003.
Table 4: Estimated Historical Energy Usage
Utah Power Idaho Rate Schedule ending March 2003.
MWh Ave kWh Est. OPe Hrs
Number of Customers 236 606,460 271 ,225
Estimated # of Meters 726 606,460 128 324 943
Review of the irrigation accounts (schedule 10) indicated 4 726 meters with an average
operating horsepower of about 90 HP. This size of connected HP may indicate many
wells and/or larger irrigation systems.
Key Market Players
4. 1 Local Irrigation Suppliers
Sunrise Irrigation [phone] (Twin Falls)Irrigation Centers - Arco
104 W. Idaho Street
Arco, ID 83213-0657 208-527 -3075
Pioneer Equipment Co [phone] (Idaho Irrigation Centers - Challis
Falls)O. Box 303
Challis, ID 83226 208- 782-0213
PPS Precision PumpingNSDs [phone] Advanced Irrigation, Inc.
(Boise)4440 S. Yellowstone
Idaho Falls, ID 83402 208-522-3703
Golden West Irrigation & Equipment Golden West Irrigation & Equipment
291 Stanley Street 2256 S. Hwy 191
Idaho Falls , ID 83405 208-524-3203 Rexburq, I D 83440 208-356-9318
NI West [phone] (Rexburg)
Federal Contacts
The USDA is offering the Environmental Quality Incentives Program (EQIP), Ground and
Surface Water Conservation Program. This program focuses on water conservation and
does not emphasize energy conservation. Although no conflicts are anticipated between
a Utah Power irrigation program and the NRCS conservation program , customers
irrigation evaluators and testers need to be aware of the NRCS program.
Idaho Irrigation Program Review
Two contacts are: Phuoc Hoang, ID Design Engineer, vinh.hoangcmid.usda.gov and
Bruce Sandoval, Irrigation Engineer (Twin Falls), bruce.sandovalcmid.usda.gov.
State Contacts
Idaho Department of Water Resources (IDWR) offers a Pump Efficiency Testing
Program. The Agricultural , Industrial & Municipal Team (AIM) is responsible for the
program. The primary contact is Stuart Van Greuningen [phone]. According
their web site over 1 000 irrigation pump tests have been done since 1984. Additionally,
the web site refers to test results showing that most of the pumps operated 150/0 below
theoretical maximum efficiency. Based on a recent conversation with Stuart, IDWR
plans to test an additional 100 pumps starting this fall and sees synergies with a possible
Utah Power offering targeting irrigation customers. Stuart indicated that historically less
than 50/0 of the participants actually make changes.
Avista Utilities offers energy efficiency incentives for Idaho customers. According to their
web site, Avista appears to offer site-specific incentives and specific programs for
variable frequency drives and premium efficiency motors.
Idaho Power offers an incentive program for Idaho irrigators. According to their web site
irrigators can receive up to $5 000 for improving the energy efficiency of a pump system
or installing a new one. The primary Idaho Power Agriculture Representative is:
Quentin Nesbit
Idaho Power Corporate Headquarters
O. Box 70
Boise, ID 83707
[phone]
PacifiCorp previously prepared the following contact information tables.
County Extension Contacts:
Count
Teton
Clark
Fremont
Butte
Madison
Jefferson
Bonneville
Bin ham
Bear Lake
Franklin
Oneida
Bannock
Caribou
Contact Address E-mailNone 89 N. Main Courthouse, Dri s, ID 83422 teton uidaho.edu
Keith Bramwell P.O. Box 65 Dubois, ID 83423 clark uidaho.edu
Janice Stim son 49 W. 1 st N, St. Anthon , ID 83445 fremont uidaho.edu
Charles Che ne P.O. Box 832 Arco, ID 83213 butte uidaho.edu
Gale Hardin P.O. Box 580 Rexbur , ID 83440 madison uidaho.edu
Geor e Hamilton 134 N. Clark Rm 30, Ri b , ID 83442 'efferson uidaho.edu
Wa ne Jones 2925 Rollandet, Idaho Falls ID 83402 bonneville uidaho.edu
Scott Nash 132 S. Shillin , Blackfoot, 10 83221 bin ham uidaho.edu
Joel Packham P.O. Box 237 , Paris, ID 83261 bearlake uidaho.edu
Stuart Parkinson 561 W Oneida, Preston , ID 83263 franklin uidaho.edu
Rauhn Pant in 30 N. 1st W , Malad, ID 83252 oneida uidaho.edu
Beck Dahl P.O. Box 4228, Pocatello, 1083205 bannock uidaho.edu
Steven Harrison 53 E. 1 st St., Soda S rin s, ID 83276 caribou uidaho.edu
Idaho Irrigation Program Review
Soil and Water Conservation Districts:
District Name
West Side
Clark
Madison
Jefferson
Caribou
Franklin
Contact Name
Mark H ndman
Norman Tavenner
Susan H mas
Mel Bri s
Wilder Hatch
Steven Chatterton
Address
1120 Lincoln Rd , Idaho Falls, 10 83401
263 E. 4th N. Rexbur ,1083440
263 E. 4th N. Rexbur , 10 83440
3862 E. 300 N Ri b ,1083442
390 E. Hoo er, Soda S rin s, 10 83276
89 E. 800 N. #3, Preston, 10 83263
Phone
208-522-5137
208-356-6931
208-356-6931
208- 7 45-6662
208 547-2558
208-852-0562
Water and Groundwater Districts:
District Contact Address Phone
Bear River Water Pete
Oist. 11 Peterson O. Box 349, Preston 10 83263 208-852-1385
Ron 900 N. Skyline Or. Suite A, Idaho Falls, 10
Water Oist. Carlson 83402 208-525-7171
Bingham Ground Craig
Water Oist (GWO)Evans O. Box 42, Pingree, 10 83262 208-684-9634
Bonneville/Jefferson Robert 6330 West 33rd. South, Idaho Falls, 10
GWO Martin 83402 208-522-0399
Richard
Madison GWO Smith No contact info.
Rauhn
Oneida Panting 30 N. 1st W , Malad, 1083252 oneidalW.uidaho.edu
Becky
Bannock Dahl O. Box 4228, Pocatello, 1083205 bannocklW.uidaho.edu
Steven
Caribou Harrison 53 E. 1st St., Soda Springs, 1083276 cariboulW.uidaho.edu
REVIEW OF IRRIGATION PROGRAM DESIGNS
PacifiCorp has reviewed other irrigation program designs in the process to best select a
design with a "best fit" for Idaho customers. Part of this process involved categorizing
source of savings for irrigation systems into the following areas:
Education - operational changes that tailor water use and system operation to
the best available weather and crop conditions.
Pump tests/repairs and replacement
System modificationslrepairs and replacement.
These sources of savings are progressively more expensive to obtain (from both a
customer and utility perspective), but are more persistent as well. Review of other
irrigation programs indicate high requests for low or no costs services like pump tests
combined with low overall implementation rates are likely outcomes and adversely
impact cost effectiveness. To counter this, many programs combine lower cost savings
with higher cost approaches to help maintain cost effectiveness. This is the approach
proposed here.
Idaho Irrigation Program Review
A program design recently proposed by the Energy Trust of Oregon for PacifiCorp
Oregon territory and analyzed for applicability to PacifiCorp s CA service territory
appears to represent an effective approach to low cost savings as well as some
intermediate steps to help insure implementation of the more costly savings. As such
this program design forms the framework for the proposed Idaho program. Subsequent
discussions with growers and irrigation suppliers about the proposed design indicated a
need to include simple pivot equipment changes into the program and the pivot
equipment incentives were added for four measures.
Analysis assumptions and projected savings from estimated participation are
summarized in this document with supporting details provided in an attached
spreadsheet. Assumptions about program start dates and annual vs. partial year
results may cause some totals to be off slightly. Overall program performance is
anticipated to be similar to the overall projections. A printout of the spreadsheet is also
located in Appendix C. The most current spreadsheet summarizing program savings
and costs is displayed in Appendix D.
The proposed program components are:
Nozzle Exchange Program
Pump Screening & System Audit
Pump Testing Program
Center Pivot Equipment
This proposed program design appears to be comparable with other market offerings to
irrigators including the Idaho Department of Water Resources pump testing program
which has tested 1 000 pumps to date and plans to target another 100 starting last fall.
Avista Utilities and Idaho Power s incentive programs for irrigation customers appear to
be similar to the incentives and services offered by PacifiCorp s FinAnswer Program in
W A and UT which will be the same as the program filed in Idaho. .
RECOMMENDED PROGRAM DESIGN
The demographics of the Idaho irrigation accounts show a large number of sprinkler
irrigators (center pivots, hand and wheel lines). Irrigation seasons and associated
energy usage per system vary throughout eastern Idaho. Based on the diverse mix of
irrigation methods it is recommended that the irrigation program be similar to proposed
program design. The main components are summarized in this section.
When estimating the amount of energy savings and costs for each program component
the goal was to produce reasonable yet conservative estimates.
Nozzle Exchange
The proposed nozzle exchange part of the program will provide new standard brass
sprinkler nozzles to replace worn ones. This part of the program will target irrigators with
hand lines and wheel lines as well as solid set sprinklers systems. Additionally, flow
control nozzles will also be part of the program.
Primary design elements for the nozzle part of the program are:
No limits on the maximum number of nozzles.
Flow control nozzles will also be available and allowed to replace worn standard
nozzles.
Idaho Irrigation Program Review
Solid set sprinklers will be allowed.
Equipment suppliers will decide which nozzles are appropriate for participants.
Participants will have new nozzles in hand prior to replacement and returning old
ones. A limited provision will be made for irrigation customers to return nozzles after
the new ones are installed.
Center pivots sprinkler packages are covered under a separate portion of the
program.
The primary time to replace nozzles is during the irrigation off-season; Le, November
through March.
4. 1. 1 Primary Assumptions for Nozzles in the Nozzle Exchange portion of the
program
. 4 726 potential meters from schedule 10 accounts
. 4.50/0 estimated annual participation rate
2 systems per meter (Le. 2 wheel lines)
84 nozzles per system on average
. 1 504 kWh average savings per system, assumes 33 5/32" nozzles worn 1.
sizes larger and 1 940 average operating hours
. $57.10 nozzle cost per system, assumes 800/0 standard brass nozzle , 100/0 flow
control and 10 % solid set with brass nozzles
. $51.24 customer cost per system , assumes $0.61/nozzle labor
43 gpm (15 acre-feet/year) potential water savings per system (0.18 acre-feet per
nozzle)
4 year measure life
1/3 of the nozzles are not installed or produce energy savings
The energy savings from nozzle replacement is dependant on a reduction of water flow.
The estimated potential water savings is about 0.18 acre-feet per nozzle per year.
Taking into account that 1/3 of the nozzles are not implemented, the average water
savings is closer to 0.12 acre-feet per year for each nozzle purchased.
Irrigation accounts such as the irrigation districts were not identified and will not have
any nozzles to replace. Overall projected Nozzle Exchange participation is not likely to
be materially affected by these district customers.
Primary Assumptions for Gaskets and Drains in the Nozzle Exchange
portion of the program
Later during program development and to provide more options for irrigation customers
to achieve energy savings , pipe gaskets for hand lines and low pressure drains for wheel
lines were included in the Nozzle Exchange.
The primary assumptions for are:
Participation rate is approximately ~ that of nozzles
. 1 604 kWh/year for fixing drains or gaskets per system (1.250/0 of average annual
usage)
33 drain and gaskets per system
. 48.6 kWh/year potential energy savings per drain or gasket
. 0.357 acre-feet per year potential water savings per drain or gasket
500/0 will not be installed or produce energy savings
Idaho Irrigation Program Review
. $1.50 average cost per gasket
. $0.61 installation labor cost per gasket
. $7.50 average cost per drain
$1 installation cost per drain
A check was done to see if the amount of energy savings calculated was reasonable.
Assuming a small 1 gpm leak from a drain or gasket produces about 91 kWh in potential
savings, so the original calculations of 48.6 kWh per year in potential savings are
conservative.
Implementation
The overall program is designed to be delivered by a third party (program administrator)
under contract with Utah Power. The program administrator will be responsible for
identifying and enlisting the support and cooperation of existing irrigation supply stores
who will inventory equipment and provide them to irrigators. The expanse of the
company service territory makes it important for the program administrator to enlist as
many geographically distributed irrigation supply stores as possible.
The benefits and logistics of the nozzle exchange program will be provided to irrigators
through short classes or information sheets developed as part of an overall
communication plan and delivered by the program administrator.
Pump Screening & Water Management Consultation
The pump screening portion of the program is a simple audit of a customer s irrigation
system promoting irrigation management and identifying energy savings opportunities.
The primary energy savings opportunities of the pump screening portion of the program
include:
1. Information on irrigation management2. Information on pump operation to minimize demand charges3. Identifying worn sprinkler nozzles and refer to the nozzle exchange portion of the
nozzle program4. Identifying leaks from sprinklers, gaskets, hoses , drains and valves5. Identifying inefficient pumps for the pump testing portion of the program. This will
be done by measuring the wire-to-water efficiency using the utility meter
measuring pressures, lift, and estimating flow. It does not include direct
measurement of voltage, amps, power factor or flow directly.
6. The preferred time to do this work is in early spring for making impacts and
referrals to the nozzle and pump testing program. The work can be done when
the system is operating with a growing crop.
Primary Assumptions
. 4 726 potential meters from schedule 10 accounts
. 4.50/0 estimated annual participation rate
2 systems per meter
$200 to $250 per participant depending on the program year
3 year measure life
500/0 of participants will implement changes
. 3 200 kWh average savings per system (2./0 average meter usage)
Idaho Irrigation Program Review
Implementation
The program administrator will be responsible for performing the pump screening visits.
If it's cost effective, existing infrastructure including the consultants who perform pump
tests for IDWR may be available for this work. Individuals or firms performing the pump
screening work will have to work closely with the nozzle exchange, pump testing and
pivot measure portions of the programs.
Irrigation accounts such as the irrigation districts were not identified but would benefit
from a pump screen as a first step toward a pump test. The overall savings available to
the program will not be materially impacted by the absence of crop related water
management opportunities.
Pump Testing
The proposed pump testing portion of the program will be a full pump test with some
audit of the irrigation system. This will include measuring pump lift, flow, electrical
demand and system pressures. This service goes beyond pump screening by directly
measuring voltage, amps, power factor and flow.
Based on the demographics of the Idaho customers, a pump testing program is likely to
have many center pivots and wells to test.
Primary Assumptions
. 4 726 potential meters from schedule 10 accounts
. 4.50/0 estimated annual participation rate + 300/0 of pump screenings
$300 testing cost per pump
7 year measure life
About 15 of participants will implement changes
23,400 kWh average savings, assumes 100/0 Overall Pumping Efficiency (OPE)
Increase.
. $3 500 average pump repair cost.
500/0 cost share
Implementation
As with other portions of the program, this portion will be delivered by the program
administrator who will be responsible for finding and securing qualified contractors to
perform this work. Pump tests will be performed on pumps that have been through the
screening portion of the program , so coordination between each program component is
necessary.
It is assumed that pump repairs and replacements will be recommended based on
energy savings and eligibility. The level of cost share depends on repair cost and
energy savings.
A different utility - customer cost share may have to be designed if the customer is
participating in the NRCS EQIP cost sharing program, which could be up to 750/0.
It is expected that the testing large lift pump stations could be done under the pump
testing portion of the program.
Idaho Irrigation Program Review
Deep Well Turbines
Deep well turbines are relatively simple to test, but the measurement of water levels can
be misleading sometimes. If care is taken , it is recommended that deep well turbines be
included in the pump testing portion of the program. The main program challenge
presented by large wells is that any changes would be expensive. Utah Power needs to
be careful on making specific recommendations. Possibly, the pump testing portion of
the program could leave specifics to the suppliers and owner with pump test
recommendations being OPE based.
Pump tests can be done whenever the pumps are running. Testing during later summer
is generally preferred because most systems are operating at that time and any changes
are likely not to take place until after harvest.
Center Pivot Equipment
Replacement of equipment specific to center pivots was not originally part of the
proposed irrigation efficiency program. The Franklin Soil Water Conservation District
more recently estimated the number of center pivots using aerial photographs to be
876 within the Idaho service territory and pivot owners expressed an interest in having
easy to access incentives for equipment replacement measures. As a result the
program design was modified to include prescriptive incentives for certain center pivot
equipment. Eligible equipment includes replacement of sprinkler pressure regulators
and low pressure drains, replacement of worn sprinkler packages and conversion to dual
sprinkler nozzle packages.
4. 1 Sprinkler Pressure Regulator Replacement
Typical pressure regulators are installed before a sprinkler to provide a relatively
constant pressure at the sprinkler. When regulators fail , the sprinklers may operate at
higher pressures discharging more water potentially using more energy.
Primary Assumptions
. 2 876 potential center pivots
About 125 pivots participate in multi-year program
. 17 139 pressure regulators replaced over the program life
4 year measure life
226 kWh potential energy savings per regulator (assumes a 17/64" nozzle
changes from 20 to 15 PSI operating pressure). Energy savings estimates
ranged from 100 to 300 kWh depending on pumping lift assumed.
0.44 acre-feet per year per regulator potential water savings
500/0 of regulators will not be installed or at a location that produce energy
savings
. $6.50 average cost per regulator
$2 per regulator for installation labor by owner
/mp/ementation
Equipment suppliers should be primarily responsible for helping customers select the
proper pressure regulator taking into account the flow, operating pressure, and target
output pressure desired. The program administrator will develop procedures for offering
these incentives, including arranging for pre and post installation inspection of the sites
where this equipment is installed. Procedures will be posted on the Company web site
Idaho Irrigation Program Review
and data collected from the inspections will be made available to the evaluators and to
assess program effectiveness.
Low Pressure Drain Replacement
Low pressure drains are typically located near the end of each pivot span. If the drain
leaks during normal pivot operation a significant amount of water can be lost or applied
unnecessarily.
Primary Assumptions
. 2 876 potential center pivots
150 pivots participate (about 50/0) in a multi-year program
. 1 345 low pressure drains over the life of the program
4 year measure life
732 kWh potential energy savings per drain (assumes a 4 gpm leak for 1 940
hours). Energy savings estimates ranged from 360 to 1 000 kWh depending on
pumping lift assumed.
1.42 acre-feet per year potential water savings per drain
500/0 of drains will not be installed or at a location that produce energy savings
. $7.25 average cost per drain
$2 per drain for installation labor by owner
/mp/ementation
Equipment suppliers should be primarily responsible for helping customers select the
proper low pressure drain. The program administrator will develop procedures for
offering these incentives , including arranging for pre and post installation inspection of
the sites where this equipment is installed. Procedures will be posted on the Company
web site and data collected from the inspections will be made available to the evaluators
and to assess program effectiveness.
Qualified Sprinkler Package Replacement
This portion of the program offers to replace the existing sprinkler package with a new
more efficient one. The offer is available to those with worn sprinkler packages and
those who can reduce their application rate by at least 1 gallon per minute per acre.
Potential candidates include old center pivots with overhead impact sprinklers , and those
with an older sprinkler package that can reduce pivot flow rate.
3. 1 Primary Assumptions
. 2 876 potential center pivots
136 pivots participate (about 50/0) in multi-year program
4 year measure life
. 21 584 kWh potential energy savings (assumes a savings of 1 gpm/acre).
Energy savings estimates ranged from 10,000 to 30 000 kWh depending on
pumping lift assumed.
500/0 of new sprinkler packages will not be installed with pumping conditions that
provide energy savings
. $3 500 average cost per new sprinkler package , with drops and regulators
$320 installation labor cost by owner
Idaho Irrigation Program Review
/mp/ementation
Equipment suppliers should be primarily responsible for helping customers select the
proper sprinkler packages. The program administrator will develop procedures for
offering these incentives, including arranging for pre and post installation inspection of
the sites where this equipment is installed. Procedures will be posted on the Company
web site and data collected from the inspections will be made available to the evaluators
and to assess program effectiveness.
Dual Sprinkler Packages (Normal Flow and Lower Flow)
This change includes adding a sprinkler nozzle clip and a second nozzle at each drop
tube or current sprinkler position. In essence the center pivot would have two sprinkler
packages, one design for irrigating during the peak conditions and another to irrigate
with during low water use periods. For example: a sprinkler package designed for 5.
gpm/acre could be used during the spring while the plants are germinating to small
plants. The 5.5 gpm package would be swapped and the second set of nozzles
designed for a higher application rate (Le. 7.5 gpm/acre) would operate through the peak
growing season.
Primary Assumptions
. 2 876 potential center pivots
50 pivots participate (about 20/0) in a multi-year program
4 year measure life
. 10,792 kWh potential energy savings (assumes 7.5 gpm/acre pivot operating
of the time with the lower flow sprinkler package of 5.5 gpm/acre). Energy
savings estimates ranged from 5 300 to 15,000 kWh depending on pumping lift
assumed.
500/0 of new sprinkler packages will not be installed with pumping/operating
conditions that produce energy savings
$500 average cost for dual sprinkler assemblies
$40 installation labor cost by owner
/mp/ementation
Equipment suppliers should be primarily responsible for helping customers select the
proper sprinkler packages. The program administrator will develop procedures for
offering these incentives, including arranging for pre and post installation inspection of
the sites where this equipment is installed. Procedures will be posted on the Company
web site and data collected from the inspections will be made available to the evaluators
and to assess program effectiveness.
System Re-designs and Major Replacements
System design, re-design and major replacements beyond pump repairs or
replacements will receive project specific engineering and incentives. These projects are
expected to be the minority of participants in the program. Incentives for pump repairs,
replacements and system re-designs will be calculated according to a formula that will
mirror the Energy FinAnswer incentive formula. Available incentives will be similar to the
Avista and Idaho Power offers for Idaho irrigation customers.
Idaho Irrigation Program Review
Current program discussions assume the following for system redesigns or
modifications:
15 participants in a multi-year program
7 year measure life
800 kWh/yr energy savings, twice estimated for pump repairs.
000 average cost
500/0 cost share
875 average cost for engineering
Idaho Irrigation Program Review
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Appendix A: Idaho Irrigation Accounts by City
This appendix summarizes the number of irrigation sites (schedule 10) and total
horsepower demand for each city. Horsepower data was generated from 3-year
average metered kW from 2001 thru 2003. The data was sorted based on billing
addresses. There were 128 of the 4 726 billing addresses with cities located outside
Idaho. These cities are shown at the end of Appendix A.
IQ9Q2IErig_~~i2rJAccounts by Cit
---
r--
- ... ..,- "---'
jAverage!I 'Total Total Total Total August
1- . ___Billi ~~(j_cl!!~!;1) Ymc:!tym~~I1i!;l m _1 ~-~; mLt1J~t~ e~~ fl~:r !I:~:~ti 1
~~~~~~~~~%m---~F---.-!t~1
~--~~~~-
~=~:3~1~~ 4, o
~ 71
liJ
!~~;~~
~t==~
~~!~
BOISE ID 83713 10 491
.-..-.....................................--.............................. .... ....-...................-.-...,.....-......-.--... --..-................-.... .
BURLEY ID 83318 971 981 901
................................................................................................................... --....-.-.........-...........j..............-....... ...................._.........~........... ....................)....-......... .......
g~~~~~~~D
~262----
------ --
1 ~
._----
~~~I-- --~~~I-- --1~~1 .---- 420!
-------____
m__m --t-- -----_.
---------
l-------
j- --- --
i-_m_CLIFTON ID 83228 281 1 188i 1 1411 1 1731 5151
IQfu1..&~I
~~g~~ -..
1=="3I:~~L ~~~f
-=~
:DOWNEY ID 83234 591 2 0431 2063 3701 582' 231
-DUBOIS ID 83423 ,64 71 646~ 6431 641 129;
gg:~:Q):~:.::I:p::.?4?~::::::.
::_. ........-...............-...... .....-
1----"-..- ..
.... ........?.,
???J.......... ...
....._......~..
1_.1....
.. ......._.._..........
?~I..........__....
....._
..1'
~..._j......._.._...............
1..FELT ID 83424 3! 106 105 211 131
.................................................................;.......-"......-...........................................
1........-.......... ....
................-..... .. .........-...............................,.......... ................-......:"~-
~E~c:-=i=1:1:=~1==
!;!
~jc==
~=~
FRANKLIN ID 83237 151 3951 319; 2431 61
-------------------,,---- --------
_m____
_------------ -------- -------
GENEVA ID 83238 9! 7811 781 5931
:HAMER ID 83425 2641 34 0781 33 9751 31 6891 27,48
HOWE ID 83244 1 15 6271 14 7921 13 9811 11 844! 94:
--.
"""'_m."""".
"".""'."""'."..""'..."'..'.'..,. ...,.......,...,........"..".....-.........""..,,-.,,"...-"'..""""""'..""".-'-"."".....'.....'"....",,-....'..'."..............
J"..
.."..".....-......."....----.,..,....,.-"""'.""'
1.'.
""""..""'....""."""'--.--"'-"""""""';"'.".,....... ,..,.. "".".""".'."'.'..
.""- .",'.."""..m.,,_._""""""."""~""""m,,+_."".""_".""".
""'."........."..,
'IDAHO FALLS ID 83401 1321 13 5551 12 6901 9 788 7,4441 741
................... .......... .., .".....,... ........................................................""...... "" ....-..............-............."..,................-..,-..........,................... '-....-....-.......'.....j...""'.-"".""""".""""...'..-...................""............,..................................-.................................",,............................-....................-.."""""".....""...'..............""""""""....."".....""""....-......""..."".,""""..""...""""..""""..........................
AHO FALLS ID 83402 3301 38 104! 33 728! 28,630 24 816! 871
-"""..."""".""...""",."....""".....".""."."""""""".....,,""'...""".'-"""""".""..""-.'.
""'."'....-..""..__m
j....",.......-....'..."".'."" ....-....,,-..""
't-.
, ...... ..."...."'.........
m..._""....""..--""....-..L""................-...""......-.........-......""J.""..-...
........."""",..-.......""".......-.... "....".. ._...."..,.,.._...""......."-_....~........_"....._""...,........,,...........
0 FALLS ID 83403 50! 17 3021 14 5861 14 9821 12 3541 3001
8~tI f~=m I" ..
~. ...
~ ~ ~-=J.~~:~I~-
: ~n
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-=~
ilDAHO FALLS ID 83406 63 3 960 3,3711 2 831 i 1 511 i
iQNA.
...q.....?~.
4??
............................................
. i......... .
........
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....
............... 3~!I..
:......... .....m.
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:~AY~~9T~PRINGS ID 83246 18 5591 553! 4291 224:
~~!:\PQR~m IPm~?4~4_.. m1 !mm -_?'?Ql ?2~J
...
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Idaho Irrigation Program Review
A pp~~~ i)i(A: ~ ~ ~~i...
~~~ -
T-.... -.
r....IAveragel
Total Total Total Total August No. June July 1 August !September! HP per
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Idaho Irrigation Program Review
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Idaho Irrigation Program Review
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Weighted Ave.
Idaho Irrigation Program Review
Appendix B: County Demographics of Idaho Irrigation Customers
2002 Census of Agriculture: County Summary
County Bannock Bear Lake Bingham Bonneville Butte Caribou Clark
Irrigated Farms (#)644 271 979 690 145 198
Irrigated Land, Acres 177 43,499 322 801 141 823 258 219 085
Irrigated Pasture. Acres 393 645 817 10,167 10,687 330 063
Potatoes. Acres 324 68,767 29,436 161 6,468
Forage, hay and haylage. Acres 30,407 844 969 36,510 35,237 28,854 16,696
Sugarbeets for sugar, Acres 25,574
Vegetables, Acres
Orchards, Acres
Cattle and Calves
, #
20,892 689 75,193 15,676 29,862 745
Estimated Idaho Irrigation Customers From Census Data
County Bannock Bear Lake Bingham Bonneville Butte Caribou Clark
% of Irrigation Served 60%80%25%30%10%40%95%
Irrigated Farms (#)386 217 245 207
Irrigated Land, Acres 33,106 34,799 80,700 42,547 826 26,888 29.531
Irrigated Pasture. Acres 036 516 204 050 069 732 910
Potatoes, Acres 794 192 831 116 587
Forage, hay and haylage, Acres 18,244 38,275 242 953 524 542 15.861
Sugarbeets for sugar, Acres 394
Vegetables, Acres
Orchards, Acres
Irrigation Method Bannock Bear Lake Bingham Bonneville Butte Caribou Clark
Center Pivot 33%15%33%33%33%20%33%
Side Roll 18%18%18%18%18%40%18%
Hand Move 16%15%16%16%16%30%16%
Solid Set
Liner/Big Gun
Gravity 31%50%31%31%31%31%
Drip
Acres by Method
Center Pivot 10,866 220 26,487 965 912 378 693
Side Roll 996 303 617 706 055 10,755 349
Hand Move 226 220 740 717 920 066 662
Solid Set 643 676 567 826 113 344 573
Liner/Big Gun
Gravity 10,325 17,400 25,169 13,269 817 344 210
Drip
# Systems Ac./Each
Center Pivot 120 221 116
Side Roll 26.225 236 548 289 403 201
Hand Move 261 261 637 336 403 233
Solid Set
Liner/Big Gun
Gravity 120 145 210 111
Drip
Idaho Irrigation Program Review
Appendix B: Continued
2002 Census of Agriculture: County Summary 9/13/2004
County Franklin Fremont Jefferson Lemhi Madison Oneida Teton Total
Irrigated Farms (#)441 336 669 270 382 229 193 5,479
Irrigated Land, Acres 155 103 065 202 620 75,153 115 750 32,487 55,715 1 ,350 807
Irrigated Pasture, Acres 909 659 335 783 086 900 581 160 355
Potatoes, Acres 351 788 34,617 066 205 978
Forage, hay and haylage, Acres 39,919 061 97,958 647 039 856 779 533,776
Sugarbeets for sugar, Acres 574
Vegetables, Acres
Orchards, Acres 101
Cattle and Calves, #886 13,411 844 313 081 914 867 423 373
Estimated Idaho Irrigation Customers From Census Data
County Franklin Fremont Jefferson Lemhi Madison Oneida Teton Total
% of Irrigation Served 100%25%85%100%60%15%
Irrigated Farms (#)441 569 382 137 069
Irrigated Land, Acres 46,155 766 172,227 758 115 750 19,492 357 196 978
Irrigated Pasture, Acres 909 3,415 11,335 839 086 740 1 ,437 19,875
Potatoes, Acres 088 620 34,617 060 933
Forage, hay and haylage, Acres 919 765 83,264 932 039 314 817 89,238
Sugarbeets for sugar, Acres
Vegetables, Acres
Orchards, Acres
Irrigation Method Franklin Fremont Jefferson Lemhi Madison Oneida Teton Total
Center Pivot 20%33%33%33%33%33%33%
Side Roll 40%18%18%18%18%18%18%
Hand Move 30%16%16%16%16%16%16%
Solid Set
Liner/Big Gun
Gravity 31%31%31%31%31%31%
Drip
Acres by Method
Center Pivot 231 8,457 528 233 991 398 743 58,450
Side Roll 18,462 667 194 681 965 530 514 677
Hand Move 847 068 190 593 18,274 077 319 823
Solid Set 308 500 345 248 379 162 825
Liner/Big Gun 198 133 227
Gravity 308 036 714 172 36,100 079 606 980
Drip
# Systems Ac./Each
Center Pivot 120 471 317 487
Side Roll 26.692 175 170 786 132 338
Hand Move 692 203 359 914 154 541
Solid Set 115 167 112 191
Liner/Big Gun
Gravity 120 448 301 566
Drip
Idaho Irrigation Program Review
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Appendix C: Continued
Idaho Pump Screening Program
Idaho Irrigation Accounts
Using Trust Asssumptions Using New Asssumptions726 sites 4 726 sites9% 4.425 213
425
50%
213
3 Years
250
200 kWh
680,544 kWh
$ 53 168
Energy Trust Assumptions
For Klamath
186
Participants
Participants
# Systems per Participant
# Systems
Participants that change
Systems that change
Life of Measures
Cost
Energy Savings
Total Annual Savings
Annual Incentive Cost
Possible Savings Opportunites
Irrigation Scheduling
Proper Pump Operation
Refer to Pump Testing
Nozzle Replacement
Addressing Leaks/Problems
Total
Average Usage per Site
Schedule 10 Accounts
3 years
360
000 kWh
116 000 kWh
66,960
3 Years
360
000 kWh
552 040 kWh
$ 153,122
0% Possible demand savings
0% Savings under pump testing
0% Savings under nozzle exchange
0% Fixing leaks: sprinklers, drains and gaskets
0% for two systems
Total
# Sites MWH726 606,460
Average
kWh
128 324
Per SystemSavings Savings
kWh50% 3 208
Estimated Savings for Drains and Gaskets
Original savings was estimated at 5% per system site with 2 systems.
From above, savings is about 2.50% per system for drains and gasketsDividing equally 1.25% for fixing drains
25% for fixing gaskets
604 kWh for drains
604 kWh for gaskets
33 per system for wheel lines
33 per system
48.61 kWh
48.61 kWh
Estimated Savings is
and
Number of drains replaced
Number of gaskets replaced
Potential Savings per drain
Potential Savings per gasket
Check of Savings from Leaking Drains and Gaskets
Initial
Leak
GPM
Proposed
Leak
GPM
Pump
Operating
PSI
Operating
ours
940
Savings Savings
GPM Acre-Feet1 0.357
Savings
047
Primary Assumptions:
Pumping efficiency 60% with no pumping lift
Pump discharge pressure is constant
Savings
kWh
Idaho Irrigation Program Review
Appendix C: Continued
Idaho Pump Testing Program
Energy Trust Assumptions
Sites 2030 726 726
Participation Rate
50% of Irrig. Dist. & USSR pumps 213 Sites 47 Sites
+ 30% of Screening 128
Total Sites 146 340 111
Cost per Test 400 400 300
Repair/Replacement Participation 15%15%
Repair/Replacement Participation
Savings per Pump, kWh 384 384 23,400
Life, Year
Repair Cost $200 200 500
Incentive 50%50%50%
Incentive $600 600 750
Total Incentive $13,140 30,624 718
Total Savings, kWh 315 010 734 171 129 941
Total I ncentive Cost 540 166 733 036
T mal Cu&omer CO& $13,140 30,624 718
Estimate of Energy Savings
Average Pre-Test Proposed Savings Savings
Op Hours kWh Efficiency Efficiency kWh
66.394 940 128 804 45%55%12.23,419
Idaho Irrigation Accounts
Using Trust Assumptions Using New Assumptions
Idaho Irrigation Program Review
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Appendix D: Summary of Idaho Irrigation Efficiency Program
Summary of Idaho Irrigation Efficiencv Program rev 8-31-
Savings Estimates (per unit)
Nozzles, Gaskets and Drains
11.kWh/vr deemed savinas oer nozzle
24.kWh/yr deemed savinas per aasket
24.kWh/yr deemed savinas per drain
200.kWh/vr deemed savinas oer irriaation manaaement consultation
23,400.Estimated kWhlvr savinas oer Duma reoair/reolacement
46,800.Estimated kWhlvr savinas for system redesians/modification
Center Pivot Equipment
113.kWh/yr deemed savinas per sprinkler pressure reQulator
366.kWh/yr deemed savinas per low pressure drain
10,792.kWh/yr deemed savinas per replacement sprinkler packaae
396.kWh/yr deemed savin as oer dual sprinkler packaae
bal05 2006 2007 Estimated Program Participation
yr1 yr2 yr3 Total
372.976.976.91,324.Est. Number of Nozzles
343.744.17,744.36,831.Est. Number of Gaskets
343.10,742.10,742.22,827.Est. Number of Drains
10.320.256.586.Estimated Number of Checks/lIT. Manaaement
10.207.158.375.Estimated Number of Pump Tests
15.Number of pump repairs (5% of tests)
15.Est. Number of System Redesians/Mod.
213.053.053.319.Est. Number of Pivot Sprinkler Pressure Reaulators
159.593.593.345.Est. Number of Pivot Low Pressure Drains
65.65.136.Est. Number of Replacement Sprinkler Packaaes
23.23.50.Est. Number of Dual Sprinkler PackaQes
Energy Savings
yr1 yr2 yr3 Total
63,926.511,414.40 511,414.40 086,755.kWh for Nozzles
634.431 179.431 179.894 993.kWh for Gaskets
634.261 030.261 030.554 696.kWh for Drains
000.024 000.819,200.875 200.kWh for Checks/lrr. Manaaement
187 200.163,800.351 000.kWh for Pump Repairs
374,400.327 600.702 000.kWh for System Redesians/Modifications
137,069.909,989.909,989.957 047.kWh for Pivot Sprinkler Pressure ReQulators
58,194.217 038.217 038.492,270.kWh for Pivot Low Pressure Drains
752.701,480.701,480.1,467 712.kWh for Replacement Sprinkler Packaaes
21,584.124 108.124 108.269 800.kWh for Dual Sprinkler Packaaes
442 795.741 839.4,466,839.651,474.total kWh savinas
051 541 510 102 total aMW savin as
Idaho Irrigation Program Review
Program Costs (per unit)
Nozzles, Gaskets and Drains
material cost per nozzle
material cost per gasket
material cost per drain
labor cost per nozzle
labor cost per gasket
labor cost per drain
Pump Check and Irrg. Mgmt. Consultation
cost of check and consultation - yr 1, year 2 blended at $223.44
200.223.44 250.year 3 ~ $200
Pump Tests
300.cost of pump test
150.cost of retest
750.average pump repair/replacement incentive
500.average pump repair/replacement cost
System Redesigns/Modifications
875.cost of engineering analysis
000.average incentive for system modifications
000.average cost of system modification
Center Pivot Equipment Costs
material cost per pressure regulator
labor cost per pressure regulator
material cost per drain
labor cost per drain
500.material cost per replacement sprinkler package
320.labor cost per replacement sprinkler package
500.material cost per dual sprinkler nozzles
40.labor cost per dual sprinkler package
Center Pivot Equipment Incentives
Pressure Regulators
Low Pressure Drains
900.Replacement Sprinkler Packages
400.Dual Sprinkler Packages
Idaho Irrigation Program Review
yr 1 yr2 yr3 Total PMC contract NTE Droaram costs
Nozzle incentive (100% of material cost, customer provides labor
652.29,223.29,223.100.to replace)
Gasket incentive (100% of material cost, customer provides labor
014.26,616.26,616.246.to replace)
Drain incentive (100% of material cost, customer provides labor to
072.80,565.80,565.171 202.replace)
500.500.200.125,200.Total Cost of Pump Checks/lrr. Consultation
000.100.47,400.112 500.Total Cost of Pump Tests
200.050.250.Total Cost of Re-tests
14,000.12,250.26,250.Total Incentives for Pump Repair/Replacement
15,000.13,125.28,125.Total Cost for System Redesians/Modifications Analysis
000.000.60,000.Total Incentives for Redesians/Modifications
278.48,318.48,318.103,914.Pressure Reaulator Incentives
636.372.372.380.Pivot Drain Incentives
5,400.58,500.58,500.122,400.Replacement Sprinkler Packaaes Incentives
600.200.200.20,000.Dual Sprinkler Packaae Incentives
28,600.680.1 180.31,460.I program desian
13,000.44,325.44,325.101 650.marketing & outreach
38,425.38,425.850.trackinQ and reDortina, evaluation support
250.28,700.28,700.60,650.nozzle & pivot measure program mgmt
81,003.563,725.48 520,449.165,179.PMC contract NTE
15,000.15,000.15,000.45,000.utility staff
96,003.578,725.48 535,449.210,179.utility costs paid directlv by Utah Power
000.000.000.15,000.Company marketina (not Dart of PMC contract)
000.500.500.20,000.QA (not part of PMC contract)
3 000.20.000.20 000.43 000.impact & process evaluation
13,000.32,500.32,500.78,000.
Incentives summary
15,739.136,404.136,404.288,549.Nozzles, Gasket and Drains
000.250.26,250.Pump repairs
000.28,000.60,000.System Redesigns and Modifications
914.50,690.50,690.109,294.Regulators and Pivots Drains
000.67,700.700.142,400.Pivot Sprinkler Packages
30,653.300,794.295,044.626,493.Total incentives
Program management contractor fees (excluding nozzle
incentives)
000.63,300.48,450.114 750.Pump testina (includes retests)
500.71,500.51,200.125,200.Pump Check/lrr. Manaaement Consultations
15,000.13,125.28,125.System Redesian/Modification Enaineerina Analysis
850.113,130.112 630.270,610.program management
50,350.262 930.225,405.538,685.total
Utility Droaram manaaement costs
000.000.000.000.MarketinQ and web site
000.500.500.63,000.QA and evaluation
000.000.15,000.000.staff
28,000.47,500.500.123,000.total
109,003.611 225.48 567,949.288,179.Total utilitv cost (includina incentives)
1335 Total utility cosUkwh
169,194.Total utility cosUaMW
Idaho Irrigation Program Review
Customer costs (NO Net-to-Gross Ratios in effect)
276.215.215.55,707.Labor Costs for Nozzles
819.10,823.10,823.22,466.Labor Costs for Gaskets
343.10,742.10,742.827.Labor Costs for Drains
000.250.26,250.Customer Costs for Pump Repairs
000.28,000.60,000.Customer Costs for System Modifications
032.132.20,132.43,297.Mtrl & Labor Cost for Regulator Replacement
834.113.113.061.Mtrl & Labor Cost for Pivot Drain Replacement
520.189 800.189,800.397 120.Mtrl & Labor for Sprinkler Packaqe Replacement
560.220.220.000.Mtrl & Labor of Dual Sprinkler Package Installation
641,730.total
Idaho Irrigation Program Review