20100315Annual DSM 2008 Report.pdf

~~~OUNTAIN RE '\1
201 South Main, Suite 2300
2010 MAR 15 AM 10: 04 Salt Lake City, Utah 84111
March 15,2010
VI OVERNIGHT DELIVERY
Idaho Public Utilties Commssion
472 W. Washington
Boise, il 83702-5983
Att: Jean D. Jewell
Commssion Secreta
Re: 2009 Annual Report of Idaho Demand Side Management Activities
PacifiCorp (d.b.a. Rocky Mountain Power) hereby submits for fiing an origin and eight copies
of its 2009 Demand Side Management Anual Report pursuat to Order No. 29976 frm Case
No. PAC-E-05-10.
It is respectfly requested tht all form correspondence and sta request regardig ths filing
be addrssed to one of the followig:
By E-mail (preferred):datarequestcmpacificorp.com
By reguator mail:Data Request Response Center
PacifiCorp
825 NE Multnomah Blvd., Suite 2000
Portland, OR 97232
For any questions, please contact Ted Weston, Maner, Idaho Regulatory Afais, at (801) 220-
2963.
Sincerely,~k.~¡'
Jeffrey K. Laren
Vice President, Reguation
pç:r¡,:¡\l1 '\ ;¡.,~ ..1 L.. ~ ..
2m3 MAR 15 AM \0: 05
Rocky Mountain Power
Demand Side
Management
Annual Report -
Idaho
Rocky Mountain Power Demand Side Management Team
3/15/2010
1 200910 Annual Report (3_15_10).docx
~
Table of Contents
Introduction and Executive Summary .........................................................3
2009 Performance and Activity................................................................... 5
Engagement with Commission and Interested Parties ...............................9
Load Management Programs and Activity................................................ 11
Residential Energy Efficiency Programs and Activity................................ 13
Non- Residential Energy Effciency Programs and Activity....................... 20
Market Transformation - Northwest Energy Efficiency Allance................ 26
Summary of 2009 Results: ....................................................................... 27
Balancing Account Summary................................................................... 31
Cost Effectiveness: .................................................................................. 32
Appendices: .............................................................................................38
2 20010 Annual Report (3_15_10).docx
Introduction and Executive Summary
Rocky Mountain Power (the "Company") working in partnership with its retail customers
and with the approval of the Idaho Public Utilities Commission (the "IPUC"), acquires
cost effective demand-side resources as an alternative to the acquisition of supply-side
resources. Demand-side resources assist the Company in most effciently addressing
load growth and contribute to the Company's ability to meet system peak requirements.
Company demand-side management (DSM) programs provide participating Idaho
customers with tools that enable them to reduce or assist in the management of their
energy usage, while reducing the overall costs to Rocky Mountain Power's customers.
Demand-side resources are a valuable component of Rocky Mountain Power's resource
portolio and are relied upon in resource planning as a least cost alternative to supply -
side resources.
Rocky Mountain Power currently offers seven energy efficiency and load control
programs in Idaho. Costs associated with these programs as well as the Idaho portion
of the Company's contribution to the Northwest Energy Efficiency Allance are
recovered through the Customer Efficiency Services Rate Adjustment (Schedule 191),
with the exception of the Load Control Service Credits which are paid to participants of
the irrigation load control programs (Schedule 72 and 72A) and are recovered through
general rates. The results of Rocky Mountain Power's Idaho demand-side management
activities for the reporting period of January 1, 2009 through December 31, 2009 are
summarized in Table. 1 below.
Table 1
2009 Total Portfolio Penormance
System Benefit Revenues Collected
System Benefit Expenditures (Includes NEEA, Exludes Irrigation Credits)
Total Expenditures Including Irrigation Credits
MW Under Control (Gross at Generation)
kWh/Yr Savings (Gross at Generation)
$ (5,010,48)
$ 6,432,685
$ 13,757,163
285.2
16,362,890
Portolio Cost Effectiveness
PTRC
3.731
TRC
3.392
UCT
1.831
RIM
1.470
PCT
9.734
(Note: See notes for Table 2 for explanation of Gross Savings and line loss assumptions)
Participation in the irrigation load control programs increased by approximately 20
percent from 2008 to 2009 providing the Company with 285 megawatts (at generation)
of participating load. Overall first year energy savings for 2009 achieved through
energy effciency programs, increased by more than 40 percent while Customer
Effciency Services expenditures increased 35 percent.
3 200910 Annual Report (3_15_10).docx
At the end of 2009, the Customer Effciency Services balancing account had an
unfunded balance of $ 2,238,820.27.
In October 2009, the Company initiated process and impact evaluations for several
Idaho programs including the Home Energy Savings, Refrigerator Recycling, Energy
FinAnswer, FinAnswer Express ånd Agricultural Energy Services programs for program
years 2006 to 2008. The evaluation work is being completed by an independent
evaluator (The Cadmus Group) which was selected via a competitive bidding process.
Draft and final reports for the evaluations are expected to be completed in the second
quarter of 2010, with the exception of the Agricultural Energy Services program, which
wil be completed in the third quarter.
Overall, Rocky Mountain Powets demand side management portolio was cost effective
under all five tests based on 2009 results. In addition, all demand side management
programs were cost effective based on the Utility Cost and the Total Resource Cost
tests, with the exception of the Agricultural Energy Services program. Factors
contributing to the marginal Total Resource Cost test results for this program for 2009
are outlined on pages 26 - 28. On an individual program basis, only the Irrigation Load
Control programs satisfied the Rate Impact Test.
For the period January 1, 2009 through December 31, 2009, demand side management
acquisitions for all programs produced an estimated $17.1 milion in net benefits over
the life of the savings on a Total Resource Cost basis.
4 200910 Annual Report (3_15_10).docx
2009 Penormance and Activity
Program and Sector level results for 2009 are provided on the following table 1. Program
Schedules are noted in parenthesis in the table.
Table 2
Idaho DSM Annual Result for 209
kWlYr
Savings
kWlYr (at Program
Program Units (at site)generator)Expenditures
Irriation Load Control (72 and 72A)2050 258 355 285203 $3816417.26
Total Load Control 2,050 258,35 28,203 $3,816,417.26
kWhlYrkWrSavings
Savings (at (at Program
Program Units site)generator)Expenditures
Low Income Weatherization (21)112 194,919 217,118 $197,819.17
Refrigerator Recycling (117)725 957,819 1,06,905 $108,125.50
Home Energy Savings (118)4610 1349279 150294 $593563.82
Total Residential 5,447 2,502,017 2,786,971 $899,508.49
Energy FinAswer (125)4 189,345 209,601 $49,790.48
FinAswer Express (115)33 64669 713636 $189925.40
Total Commrcial 37 83,014 923,237 $239,715.88
Energy FinAswer (125)4 1,305,202 1,440,839 $308,636.28
FinAswer Express (115)23 193,726 213,858 $73,978.69
Agricultural Energy Servces (155)225 3.994 349 4409442 $807238.30
Total Industrial 252 5,493,277 6,06,138 $1,189,85.27
Market Transformaion
Norhwest Energy Effciency Alliance 5,914,89 6,588,54 $287,190.31
Total Energy Efficiency 14,744,204 16,362,890 $2,616,267.95
Total Syem benefit Expenditures - All Programs $ 6,42,68.21
Load Control Participation Credits 2009 $ 7,324,477.43
Total Idaho Program Expenditures $ 13,757,162.64
1 Savings values in this table are shown prior to any net-to-gross adjustment. The values at generation
include line losses between the customer site and the generation source. The Company's line losses by
sector are 11.389 percent for residential, 10.698 percent for commercial and 10.392 percent for industriaL.
These values are based on the Company's 2001 Transmission and Distribution Loss Study by
Management Applications Consulting published in June 2004.
5 2009 10 Annual Report (3_15_10).doc
Major Trends and Activities:
In 2009, the Company realized substantial increases in demand side management
acquisitions in the majority of sectors and programs. Overall, first-year energy savings
from energy efficiency programs increased more than 40 percent compared to 2008,
while the Irrigation Load Control Program delivered 20 percent more participating kW for
management in 2009. At a sector lever, the Residential Sector realized 23 percent
higher savings on a kWh/year basis compared to 2008, and the combined business and
agricultural sectors delivered 78 percent more kWh/year savings than in 2008.
Expenditures related to program delivery increased in 2009 as compared to 2008.
Overall expenditures for Energy Effciency and Load Management programs (excluding
load management participation credits) increased by 35 percent compared to 2008.
When Irrigation Load Control participation credits are included, expenditures increased
by 28 percent in 2009 compared to 2008. At a sector level, the Residential sector
expenditures increased by 9 percent, business and agricultural sectors increased by
157 percent and Load Control increased by 22 percent.
Cost Effectiveness:
Consistent with the requirements outlined in Memorandum of Understanding signed by
the Company and Idaho Commission Staff, the Company provides cost effectiveness
results utilizing five Cost Effectiveness Tests;
1. PacifiCorp Resource Cost Test (PTRC) which includes a 10 percent additional
benefit for demand side resources. This is consistent with Northwest Power
Planning and Conservation Act.
2. Total Resource Cost Test (TRC)
3. Utility Cost Test (UCT)
4. Ratepayer Impact Test (RIM)
5. Participant Cost Test - (PCT)
The results for each test are provided at several levels:
1. Overall Portolio level, consolidation of all Company delivered programs
2. Load Control and Energy Effciency program portolio
3. Residential and Non-Residential energy effciency program portolio
4. Individual Program
All portolios and programs had a UCT benefit/cost ratio of more than 1.0 indicating that
for each dollar invested the benefits were greater than the required investment.
Overall, the' portolio generated $17.1 milion in Net Benefits (on a TRC basis) and was
cost effective across all five Cost Effectiveness Tests at the portolio, segment and
program level, with the' exception of theAgricultural Energy Services program noted
above.
Results of the Cost Effectiveness tests are included in the summary overview for each
program. Further details including key inputs and assumptions for each of the cost
effectiveness tests are provided in the cost effectiveness section of this report.
6 200910 Annual Report (3_15_10).docx
Program Evaluation
On October 5, 2009 Rocky Mountain Power participated in informal discussions with the
Idaho Commission Staff, Avista and Idaho Power regarding guidelines for demand side
management program cost effectiveness calculation, program evaluations, demand side
management reporting requirements and determination of prudency. In the following
weeks, Commission Staff and these investor owned utilities worked jointly to develop a
Memorandum of Understanding (MOU) that outlines expectations for program
evaluations, calculations of cost effectiveness and requirements for annual reporting of
demand side management program activities in support of a finding of prudency for
demand side management expenditures. The MOU was signed by Rocky Mountain
Power, Avista, Idaho Power and the Commission Staff and was filed on January 25th,
20102.
As part of the MOU, Rocky Mountain Power agreed to provide a timeline for when
evaluations would be completed for each program offered in the state. The Program
Evaluation Timeline (Table 3 below) provides an outline of evaluations for each program
in Rocky Mountain Power's demand side management portolio.
Table 3
Program Evaluation Timeline
Program
Evaluation
Typ
Anticipaed
Year
Complete
Program
Year(s)
Evaluated EvaluatorStaus
Home Energ Savings Process and In Process 2010 200- 200 The Cadmus Groupc
Impact
See Va Later Refrigerator
Process and In Process 2010 200- 200 The Cadmus GroupImpact
Low Income Weaterization Impact Planned 2010 2007- 200 To Be Determined
Energ FinAnswer
Process and In Process 2010 200 The Cadmus GroupImpact
FinAnswer Express Process and In Process 2010 200- 200 The Cadmus GroupImpact
Irrigation Energy savers
Process and In Process 2010 200- 200 The Cadmus GroupImpact
Irrigation Load Contrl Impact Complete Annual Annual Company Evaluated
& Reported
2 The MOW was entered by Idaho Power as part of a Stipulation in Case IPC E 09-09, filed on January
25,2010.
7 200910 Annual Report (3_15_10).docx
In October, 2009, the Company initiated third-part independent process and impact
evaluations for the Home Energy Savings, See ya later refrigerator, Energy FinAnswer,
FinAnswer Express and Agricultural Energy Services programs for program years 2006
- 2008. The draft results of these evaluations are expected to be available during the
second and third quarters of 2010. Findings from these evaluations wil be key inputs to
on-going program design and modification as well as inputs to future cost effectiveness
determinations.
As available, Rocky Mountain Power wil provide copies of the draft and final evaluation
reports to the Commission staff as well as post them on the Company web site at
http://ww.pacificorp.com/es/dsm.htmlfor public viewing.
No process, impact or market impact evaluations were completed on Rocky Mountain
Power programs in Idaho during 2009 as part of the development of this report.
In compliance with the MOU, each of the program sections in this report provides a
description of in-process or planned program evaluations. Any process or program
changes (whether the result of an evaluation or not) wil be included in the narrative
section of each program. The specific assumptions and changes to cost effectiveness
inputs (as outlined in the MOU) wil be included in the cost effectiveness appendix
(Appendix 1 of this report).
Plans for Next Year:
The Company filed a request with the Commission on February 25, 2010 to increase
the level of the Tariff Rider (Schedule 191) to better match collections with program
expenditures and to reduce the unfunded balance in the Schedule 191 balancing
account. The unfunded balance as of December 31,2009 was approximately $2.2
million. The request seeks to increase the collection rate from 3.72 percent to 5.85
percent.
The Company expects to complete the process and impact evaluations as outlined in
the previous section of this report during the second quarter of 2010 (with the exception
of the Agricultural Energy Services program evaluation which wil be complete in the
third quarter). Evaluation results for these programs wil be reflected in an update
during the third quarter of 2010 and in the Idaho 2010 Demand Side Management
Annual Report.
During 2010, the Company plans to make modifications to the Home Energy Savings
program including lighting, appliances, HVAC and weatherization or shell measures
intended to adjust to changing market conditions and further improve program
performance.
The Company wil be filing changes to the FinAnswer Express program to reflect
changes in standards for lighting, motors and HVAC equipment.
8 200910 Annual Report (3_15_10).docx
Finally, the Company is contracting for an update of the 2007 Assessment of Long-
Term System Wide Potential for Demand Side and Supplemental Resources during
2010. The update wil be used to inform the Company in the development of the 2011
Integrated Resource Plan, demand side program management and valuation.
Engagement with Commission and Interested Parties
The Company made several filngs and participated in informal proceedings with the
Commission regarding demand side management during 2009. The dates of the filings
and activities and descriptions are included below.
February 11, 2009 - Advice 09-01 Rate Schedule 72A (Irrigation Load Control)
The Company proposed changes to the Irrigation Load Control program tariff. The
changes included clarification for pre-season internet access for communications,
revised contract language related to payment options, calculation of average demand
when a customer has less than two years of usage history, revision of notifcation dates
and clarification of pricing for liquidated damages.
The request was approved on May 7,2009 with an effective date of June 1,2009.
March 18, 2009 - Rocky Mountain Power Demand Side Management 2008 Annual
Report for the Idaho Jurisdiction
Rocky Mountain Power provided its 2008 Annual Demand Side Management report to
the Idaho Commission for review.
October 5, 2009 - Informal Demand Side Management Workshop - Evaluation and
Cost Effectiveness
Rocky Mountain Power participated in an informal workshop with representatives from
the Idaho Commission Staff as well as Idaho Power and Avista. Please see the
description of the activities under the Program Evaluation heading in the previous
section of this report.
October 6,2009 - Meeting with the Idaho Irrigation Pumper's Association (IIPA)
Rocky Mountain Power met with IIPA representatives to discuss the Dispatchable
Irrigation Load Control Credit Rider program, Schedule 72A. Commission Order No.
30482 approved the load control credit level to participants for the 2008 and 2009
irrigation seasons. Parties discussed the results of the program, what worked and what
revisions could improve the program. At that meeting an agreement was reached to
continue with the existing load control credit level, remove the month of September from
the program and revise the dispatch hours.
October 28, 2009 - Advice 09-05 Rate Schedule 72A (Dispatchable Irrigation Load
Control Credit Rider)
Based on the agreement reached with the IIPA in the October 6,2009 meeting the
Company filed Tariff Advice 09-05 with the Commission requesting authority to modify
Schedule 72A. The modifications included extending the current load control service
credit schedule through the 2012 irrigation season, shortening the program season to
June through August and extending the dispatch period to 11 :00 AM to 7:00 PM
9 2009 10 Annual Report (3_15_1 O).docx
Mountain Daylight Savings time. The Commission approved the Tariff Advice 09-05 as
filed with December 31, 2009 effective date.
2009 Idaho Irrigation Load Control Quantitative Review
Rocky Mountain Power provides its annual report of the results and activities associated
with the Irrigation Load Control programs offered under Schedule 72 and 72A as a
separate report. The reporting period for the current report is October 1, 2008 to
September 30,2009. Starting in 2010, the Company intends to report on a calendar
year basis and combine that information in this Demand Side Management Annual
Report. Please see the Irrigation Load Control section of this report for more details
about changes in the reporting period. The 2009 Idaho Irrgation Load Control
Quantitative Review is included with this report as Appendix 2.
Idaho Strategic Energy Allance (Formerly the 25 x 25 Task Force)
Rocky Mountain Power participates in the Idaho Strategic Energy Allance with
representation on the Allance Board of Directors and participation on the Energy
Effciency Task Force. The Allance published a set of recommendations developed by
the Energy Effciency Task Force on October 8,2009. Among the recommendations
was to provide support to the K-12 Schools Facilities Energy Efficiency activities. The
Company anticipates supporting energy effciency analysis activities during 2010. For
further details on the Company's participation, please see the Plans for Next Year
portion of the Energy FinAnswer program description.
For more details on the Idaho Strategic Energy Allance, please go to the Allance
website at http://ww.energy.idaho.gov/energyallancel .
10 200910 Annual Report (3_15_10).doc
Load Management Programs and Activity
Irrigation Load Control (Schedule 72 and 72A)
This program is marketed as the Irrigation Load Control program (Schedules 72 & 72A)
and is offered to Idaho irrigation customers receiving retail electric service on Schedule
10. Participants agree to allow for the curtailment of their electricity usage as prescribed
in Schedules 72 and 72A in exchange for the receipt of participation credits. A report
specific to the 2009 irrigation season for this program is attached to this report as
Appendix 2 and covers the period from October 1,2008 through September 30,20093.
Savings (MW and participation) information in Tables 2,4 and 26 included in this report
were taken from that report. The costs included in Tables 2,4 and 26 reflect actual
calendar year 2009 expenditures. Please see Reporting Period Changes below.
Summary program performance, expenditures, participation and cost effectiveness
results are provided in the following table.
Table 44
200 Irrgation Load Control Program Performance
MW Under Control (Gross at Gen) 285.2
Expenditures - Total $ 11,140,895
Participation Credits $ 7,324,477
Program Operations Expense $ 3,816,417
Participation (Customers) 938Participation (Sites) 2,050
Program Cost Effectiveness
PTRC
5.80
TRC
5.280
UCT
1.813
RIM
1.813
PCT
NA
Additional information on the irrigation load control program is available in the 2009
seasonal report 2009 Idaho Irrgation Load Control Quantitative Review dated
November 14, 2009. While field and program management costs for the program are
recovered through Schedule 191, Customer Efficiency Services Rate Adjustment, the
program's customer participation credits are recovered through general rates.
Enrollment and site installations for the 2010 season are currently underway.
3 Report is dated November 14,2009
4 Paricipation results from 2009 ID Irrigation Quantitative Review, Tables one and twelve.
11 20010 Annual Report (3_15_10).docx
Major Trends and Activities
As previously mentioned, the Company proposed modifications to Schedule 72A in
Advice 09-01, dated February 11, 2009. The primary changes were revisions to tariff
language related to communications availability, estimates when usage history is
inadequate and clarification of pricing for liquidated damages. The request was
approved on May 7,2009 with an effective date of June 1,2009.
Additional modifcations were proposed in Advice 09-05, including extending the current
load control service credit schedule through the 2012 irrigation season, shortening the
program season to June through August and extending the dispatch period to 11 :00 AM
to 7:00 PM Mountain Daylight Savings time. The Commission approved Advice 09-05
as filed with a December 31, 2009 effective date.
Reporting Period Changes
Please note that the costs included in this Demand Side Management Annual Report
reflect cost associated with the Calendar Year 2009, while the costs included in 2009
Idaho Irrgation Load Control Quantitative Review reflect costs for the Seasonal Report
that runs from October 1 to September 30. Operational results and savings are
consistent between reports because the load control season occurs during June
through August of each year.
Therefore, results included in this Annual Report reflect the operations/savings and
costs for the Calendar year 2009. Cost Effectiveness was reevaluated to reflect the
difference in period costs and details are included in the Cost Effectiveness section ofthis report. .
Program costs reflected in this annual report are $460,284 higher than those reflected in
the 2009 Irrgation Load Control Quantitative Review, while the operational results and
associated savings and benefits are identical between reports. As a result, the cost
effectiveness test results are slightly lower in this annual report than those reported in
the 2009 Idaho Irrgation Load Control Quantitative Review.
For consistency and to improve reporting efficiency, beginning in Calendar Year 2010,
the Idaho Irrigation Load Control Report (or Idaho Irrgation Load Control Quantitative
Review) wil reflect calendar year results and costs, and it wil be included with the filing
of this Demand Side Management Annual Report.
Program Evaluation
Rocky Mountain Power has provided an annual report (or ID Irrgation Quantitative
Review) of the activities and results of the Idaho Irrigation Load Control Program to the
Idaho Commission each year since the program started in 2003. These results reflect
the measured actual dispatch and impact on the system. The annual reporting
12 200910 Annual Report (3_15_10).docx
approach utilizes a work plan similar to those used by third part evaluation firms and
serves as an annual program evaluation.
Plans for Next Year
Program expenditures are expected to increase in 2010 above the 2009 levels. The
increase wil provide further resources to support the program. Historically, program
delivery has been heavily supported by Company resources, but that level of support is
no longer sustainable due to the increased size and complexity of the program. The
Company expects to engage further support from external vendors for on-going delivery
of the program to address these issues as well as to maintain the reliabilty of the
resource.
The growth in the size of the load control program over the past few years is beginning
to pose some new challenges as we plan for the future. Specifically, the Company is
experiencing voltage issues on circuits where irrigation is the predominate load. The
Company is currently evaluating several potential solutions to the issue and wil provide
additional information as it becomes available.
Residential Energy Efficiency Programs and Activity
Home Energy Savings Program (Schedule 118)
The Home Energy Savings program (Schedule 118) provides a broad framework to
deliver incentives for more effcient products and services installed or received by Idaho
customers in new or existing homes, multi-family housing units or manufactured homes.
The program is delivered through, Portland Energy Conservation, Inc. (PECI), a third
part administrator hired by the Company. Program information is available to the public
at the program's web site at ww.homeenergysavings.netlidaho/home and can also be
accessed through ww.rockymtnpower.netlArticle/Article45165.html. the Company's
Idaho energy effciency program website.
Eligible program measures include: washing machines, refrigerators, water heaters,
dishwashers, lighting (both compact florescent lamps (CFLs) and fixtures), cooling
equipment and services, ceiling, wall and attic insulation, windows and miscellaneous
equipment such as ceiling fans. Incentives are provided to customers through two
methods: (1) post-purchase application process with incentives paid directly to
participating customers, and (2) mid-market (i.e., retailers and manufacturers) buy-
downs, for delivery of CFL incentives. Mid-market buy-downs result in lower retail prices
for customers at point-of-purchase and involve no direct customer application process.
13 200910 Annual Report (3_15_10).docx
Program results for 2009 are provided in the Table below.
Table 5
2009 Home Energy Savings Program Penormance
kWh/Yr Savings 200 (Gross - At Genl
Expenditures
Incentives Paid
Program Cost Effectiveness
Levelized Cost ($/kWh)
UfecycJe Revenue Impact ($/kWhl
PTRC
1.454
0.062
$ 0.0000046
14
TRC
1.322
0.062
1,502,94
$593,564
$354,913
UCT RIM PCT
1.731 0.722 6.453
0.047
200910 Annual Report (3_15_10).docx
Details of 2009 measure level participation and savings are provided on the following
table.
Table 6
2009 Home Energy Savings Measure Performance
kWh/yr
Unit Savings
Home Energ Savings Measures Measurement # of Units Participants (Gross-At Site)
Clothes Washer-Tier One Units 120 120 26,259
Clothes Washer-Tier Two Units 913 913 220,435
Dishwasher Units 320 320 9,688
Electric Water Heater Units 93 93 8,435
Refrigerator Units 310 310 30,225
Insulation: Attic Sq Feet 362,591 275 379,517
Insulation: Floor Sq Feet 16,009 16 8,586
Insulation: Wall Sq Feet 19,834 23 25,047
Windows Sq Feet 12,685 114 18,245
CAC/HP Tune up Projects 98 98 4,032
Evaportative Cooler Units 2 2 650
Central AlC Equipment Units 3 3 288
Duct Sealing - Electric Projects 1 1 2,152
Duct Sealing - Gas Projects 20 20 800
Heat Pump Conversion Units 2 2 6,294
Heat Pump Upgrade Units 3 3 2,433
Proper CAC Install Projects 1 1 23
Proper CAC Sizing Projects 1 1 67
Ceiling Fans Units 9 4 963
Fixtures Units 46 26 4,232
CFLs Bulbs 22,666 2,266 600,908
Totals 435,727 4,611 1,349,280
kWhNr Sa~ngs at Generation 1,502,950
. .. .(Note: CFL Participation 15 assumed at 10 CFLs per participant.)
Major Trends and Activities:
The Home Energy Efficiency Incentive program savings in 2009 more than doubled as
compared to 2008, while the expenditures increased approximately 20 percent versus
2008. Reasons for the 2008 reduced program performance were explained in the 2008
annual report and included the misalignment of specialty bulb pricing with the regional
offering. This situation was remedied in 2009 and helped contribute to a four-fold
increase in lighting activity and savings when compared with 2008 results.
The availability of federal tax credits and media coverage surrounding federal stimulus
funding began increasing the overall awareness and interest in providing for energy
15 200910 Annual Report (3_15_10).docx
effciency opportunities in homes. Contractors and retailers in turn have developed
marketing messages and sales materials that feature the availability of the federal tax
credit increased customer contact. Use of the tax credit as a sales tool has been
especially prominent in the window replacement and home insulation markets. The
addition of incentives for heat pumps in 2008 increased overall activity in the HVAC
market that has carried over into 2009 program results.
Weatherization activity has increased as the result of the slowdown in the new
construction markets, increasing competition among contractors now focusing on the
retrofit market. The impact has been threefold; 1) reduction in installed costs of
weatherization services; 2) near "free" deal for customers; and 3) an increase of
insulation projects. This trend has been further accelerated by the availability of the
federal tax credit. The activity accelerated in the last two months of 2009 and to better
align program incentives and intended program design with current market conditions,
the Company utilzed the notice provisions of Schedule 118 on February 3, 2010 to
inform customers and contractors that insulation incentives wil change effective March
20,2010.
Cost Effctiveness
The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix 1 provides detailed inputs used in the cost effectiveness analysis of this
program.
Program Evaluation
Please see the discussion under the Program Evaluation heading in the 2009
Performance and Activities section of this report for evaluation activities related to this
program.
Plans for Next Year
During 2010, the Company plans to make modifcations to the Home Energy Savings
program including lighting, appliances, HVAC and weatherization or shell measures.
Changes for insulation, including incentive levels adjustments are underway using the
procedure outlined in Idaho Schedule 118 with changes effective on March 20, 2010.
16 200910 Annual Report (3_15_10).docx
"See ya later, refrigerator" (Schedule 117)
The Idaho Refrigerator Recycling Program (Schedule 117) is available to Idaho
residential customers through a Company contract with a third-part program
administrator, JACO Environmental Services. Older refrigerators and freezers which
are less effcient, yet operational, are taken out of use permanently and recycled in an
environmentally responsible manner. The program's objective is to permanently retire
these older and less effcient refrigerators and freezers from the market and recycle the
units in order to avoid their re-entry or resale on the secondary appliance market. To
participate customers call a 1-800 number to schedule a pick-up. Program awareness
is generated through mass media advertising channels as well as Company channel
communications such as the program's web site, bil stuffers, and customer newsletters.
In addition to free pick-up and a nominal cash incentive, participants receive an energy
efficiency packet consisting of ENERGY STAR(!-certified compact fluorescent light
bulbs, a refrigeratorlfreezer thermometer, and energy education materials.
Program results for 2009 are provided in the table below.
Table 7
2009 "See ya later, refrigerator" Program Penormance
kWh Savings 200 (Gross - At Gen)
Expenditures
Incentives Paid
Program Cost Effectiveness
Levelized Cost ($/kWh)
UfecycJe Revenue Impact ($/kWh)
PTRC
I. ~~~~7 I
$ 0.00662
TRC
2.042
0.0317
1,066,905
$108,126
$21,750
UCT RIM PCT
1.631 0.565 NA
0.0317
Details of 2009 measure level participation and savings are provided on the following
table.
Table 8
"See ya later, refrigerator" 200 Results
Per Unit
Refrigerator Recycling Savings G ross Savings
Measure Unit Count (kWh/Yr)(kWh/Yr)
Refrgerator 566 1,149 650,334
Freezer 159 1,590 252,810
Total Units Recycled 725 903,144
Energy Sa\lngs Kits 675 81 54,675
Total (At Site)957,819
Total (At Generation)1,06,90
Total Expenditures
Total Cash Incentiws
$
$
108,126
21,750
17 200910 Annual Report (3_15_10).docx
Major Trends and Activities
Participation for 2009 was slightly higher than in 2008 however the level of participation
has been affected by the economic slowdown.
In terms of the impact of the program on the environment, processing the 725 units
resulted in the recycling of more than 90 thousand pounds of metal, 18 thousand
pounds of plastics, half a ton of tempered glass and the capture, recovery or destruction
of more than 875 Ibs of ozone depleting Chlorofluorocarbons (CFC)and
Hydrofluorocarbons (HFC), commonly used in refrigerants. The Carbon Dioxide (C02)
and Equivalent carbon dioxide (C02e) avoided from the atmosphere was equal to 7.250
tons.
Cost Effectiveness
The 2009 See ya later, refrigerator program was cost effective from both a UCT and
TRC perspective. There are no participant costs, so results of that test were not
calculated. Appendix 1 provides detailed inputs used in the cost effectiveness analysis
of this program. .
Program Evaluation
Please see the discussion under the Program Evaluation heading in the 2009
Performance and Activities section of this report for evaluation activities related to this
program.
Plans for Next Year
JACO Environmental anticipates an increase in participation as economic conditions
improve.
Several new program design features wil help add volume to the program starting in
spring of 2010. The American Recovery and Reinvestment Act (ARRA) stimulus funding
program wil allow purchasers of new Energy Star refrigerators to qualify for rebates at
local appliance retail stores while receiving the $30 incentive for turning in the older,
working appliances they are replacing. JACO wil be working with Sears, Best Buy,
Lowe's & other appliance retailers in Idaho to allow customers to have the new units
delivered and the old units picked up at the same time. This wil mean home owners
need only one appointment. JACO wil continue its retail participation after the ARRA
program has ended to make it more convenient for customers to participate in the "See
ya later, refrigerator" program.
18 200910 Annual Report (3_15_10).docx
Low Income Weatherization (Schedule 21)
The Low Income Weatherization Services program (Schedule 21) is available through a
partnership with Eastern Idaho Community Action Partnership (EICAP) in Idaho Falls
and Southeastern Idaho Community Action Agency (SEICAA) in Pocatello. These
partnerships allow for leveraging of Company funding with federal grants available to
EICAP and SEICAA, increasing the number of homes served. Rocky Mountain Power's
funding provides rebates that cover 75 percent of the cost of approved energy effciency
measures.
Income eligible households receive energy effciency services at no cost. Participants
can be either homeowners or renters residing in single-family homes, manufactured
homes and apartments.
Table 5 summarizes the program results for 2009. The reported energy savings is
based on measured savings documented in an analysis dated August 30, 2006
completed by QuanteclCadmus. The expenditures of $197,819 are those paid by Rocky
Mountain Power. Funds received by the agency from other sources (state or federal
funding) are not included.
Rocky Mountain Power's program provided funding towards the weatherization of 112
qualifying homes in 2009 with an average program cost per home of $1,766.
Table 9
Low Income Weatherization Performance -Idaho
kWh/Yr Savings (at Site)
kWh/Yr Savings (at Gen)
Expenditures - Total
194,919
217,118
$197,819
112
34
20
3
38
6
9
37
23
50
54
8
19
3
111
8
32
Participation - Total # of Completed/Treated Homes
Number of Homes Receiving Specific Measures
Ceilng Insulation
Floor Insulation
Wall Insulation
Replacement Windows
Storm Windows
Ouct Insulation/Sealing
Insulated Ooors
Attic Ventilation
Infiltration
Water Pipe Insulation and Sealing
Water Heater Repair/Replacement
Faucet Aerators
Showerheads
Programmable Thermostats
Fumace RepairlTune-up
Furnace Replacement
Compact Fluorescent Light bulbs
Replacement Refrigerators
Home Repairs
Health and Safety
19 200910 Annual Report (3_15_10).docx
Plans for Next Year
An updated impact and process evaluation is anticipated to be completed during 2010.
Non- Residential Energy Efficiency Programs and Activity
Energy FinAnswer (Schedule 125)
The Energy FinAnswer program (Schedule 125) was approved in Idaho effective May 1,
2008. This program was initially included in the Company's 2005 filing and later
removed from the filing to better align the demand side management program
expenditures with available funding under the original collection rate approved by the
Commission. 2009 represents the first full year of program operation in the Idaho
market.
The program provides Company-funded energy engineering, incentives of $0.12 per
kWh of first year energy savings and $50 per kW of average monthly demand savings
up to a cap of 50 percent of the approved project cost. The program is designed to
target comprehensive projects requiring project specifc energy savings analysis and
operates as a complement to the more streamlined FinAnswer Express program. In
addition to customer incentives, the program provides design team honorariums (a
finder fee for new projects) and design team incentives for new construction projects
exceeding current Idaho energy code by at least 10 percent.
The summary program results are provided in the table below.
Table 10
2009 Energy FinAnswer Program Penormance
kWh/Yr Savings 200 (Gross - At Gen) 1,650,44Expenditures $ 358,427Incentives Paid $ 151,234
Program Cost Effectiveness
levelized Cost ($/kWh)
lifecycle Revenue Impact ($/kWh)
PTRC
2.104 I
0.0378
$ 0.o02336
TRC
1.913
0.0378
UCT
2.88
0.0251
RIM
0.987
PCT
5.012
20 200910 Annual Report (3_15_10).docx
Details of 2009 savings by type of measure are provided on the following table
Table 11
Energy FinAnswer kWhlYr Savings (at site) by Measure Type
Compressed Air 634,436 42%Process 420,996 28%Lighting 229,128 15%HVAC 103,626 7%
Refrigeration 60,914 4%Pumping 45,447 3%
1,494,547
Major Trends and Activities
A total of eight Energy FinAnswer projects were completed in 2009 compared to five in
2008. Program specific energy savings increased more than three-times from 2008 to
2009.
The Company continues to market the program through its Customer and Community
Managers and network of trade alles in concert with the FinAnswer Express program.
The pipeline of forecasted projects is increasing when compared to 2008.
Cost Effectiveness
The 2009 Energy FinAnswer program was cost effective from a TRC, UCT, and PCT
perspective. Appendix 1 provides detailed inputs used in the cost effectiveness analysis
of this program.
Program Evaluation
Please see the discussion under the Program Evaluation heading in the 2009
Performance and Activities section of this report for evaluation activities related to this
program.
Plans for Next Year
Continue to monitor actual and forecasted participation and assess the potential
impacts of program modifications similar to those implemented in other markets.
As recommended by the Idaho Strategic Energy Allance, the Idaho State Energy
Program (SEP) initiated an energy assessment of all ofthe.K-12 schools in the state
(700+) during 2009. While the analysis work is being performed by Idaho SEP funded
contractors, school districts served by Rocky Mountain Power have asked the Company
for some additional analysis services as they prepare to prioritize their projects. The
preliminary school analysis phase wil likely be completed during 2010 and the
21 200910 Annual Report (3_15_10).docx
Company expects some customers wil utilize available utilty incentives to assist with
the funding of their most promising projects.
FinAnswer Express (Schedule 115)
The FinAnswer Express program (Schedule 115) is available to Idaho business
customers excluding those served on Schedule 10, who are eligible for program
services through the Agricultural Effciency Services program. The program is designed
to help customers improve the effciency of their new or replacement lighting, motors,
and other equipment purchases by providing prescriptive or pre-defined incentives for
the most common effciency measures. The program is designed to operate in
conjunction with the Energy FinAnswer program. Although incentives available vary, the
program provides incentives for both new construction and retrofit projects.
The program is primarily marketed through local trade alles who receive support from
Company provided sales and training team. Twenty-eight trade alles have signed
Company program participation agreements as of the end of 2009
The summary program results are provided in the table below.
Table 12
2009 FinAnswer Express Program Penormance
kWh/Yr Savings 200 (Gross - At Gen) 927,494Expenditures $ 263,90Incentives Paid $ 81,320
Program Cost Effectiveness
Levelized Cost ($/kWh)
Lifecycle Revenue Impact ($/kWh)
PTRC
o~~: I
$ 0.002419
TRC
1.455
0.05n
UCT
2.325
0.0361
RIM
0.741
PCT
4.192
Details of 2009 savings by type of measure are provided on the following table.
Table 13
FinAnswer Express kWhNr Savings (at site) by Measure Type
Lighting 748,891 89%
Non-Lighting 89,504 11%
838,395
Major Trends and Activities
2009 savings were lower than in 2008 primarily as the result of the availabilty of the
Energy FinAnswer program in 2009. Prior to May 2008, FinAnswer Express was the
sole program available to Rocky Mountain Power business (non-irrigation) customers.
22 200910 Annual Report (3_15_10).docx
On a combined basis, 2009 kWh savings from Energy FinAnswer and FinAnswer
Express increased by more than 45percent compared to 2008.
On May 6, 2009, Rocky Mountain Power provided lighting training in combination with
the Northwest regional trade ally network training in Idaho Falls, 49 individuals attended.
Cost Effectiveness
The program is cost effective on a TRC, UCT and PCT cost basis. Appendix 1 provides
detailed inputs and assumptions used in the cost effectiveness analysis of this program.
Program Evaluation
Please see the discussion under the Program Evaluation heading in the 2009
Performance and Activities section of this report for evaluation activities related to this
program.
Plans for Next Year
The Company wil file changes for selected components of the lighting, motors, HVAC
refrigeration offers to reflect the effects of changes in codes and standards.
Agricultural Energy Services (Schedule 155)
Agricultural Energy Services, marketed as Irrigation Energy Savers (Schedule 155),
was available in 2009 to Idaho irrigation customers taking retail service on Schedule 10
through a Company contract with third-part program delivery vendor. The program
design is intended to be the energy effciency coplement to the Irrigation Load Control
programs offered under Schedules 72 & 72A. The 2009 program included the following
customer service and measure components:
· Equipment Exchange - Provides new standard brass sprinkler nozzles to replace
worn ones on hand lines, wheel lines and solid set sprinklers systems. Gasket
and drain equipment also qualifies.
· Pivot and Linear Equipment Upgrades - Incentives are provided for certain pivot
and linear system measures including sprinkler packages and regulators. The list
of prescriptive incentives is not designed to be exhaustive and other pivot
measures are eligible for incentives if energy savings can be calculated and the
customer incurs costs to make the changes.
· System Consultation - This service provides a simple site specifc audit of a
customets irrigation system to promote irrigation management and identif
energy savings opportunities. This consultation provides information prior to a full
pump test.
· Pump Testing - The pump test includes directly measuring pump lift, flow,
electrical demands and system pressures and is performed after the pump has
been screened and the owner's financial investment criteria understood.
23 20010 Annual Report (3_15_10).døc
. System Analysis - The program provides energy engineering to help growers
quantify the costs and savings of their system effciency upgrades. Often these
upgrade decisions are made in conjunction with operational production change
considerations impacting a growers equipment needs. Incentives are based on a
standard formula tied to costs and first year energy savings.
The summary program results for 2009 are provided in the table below.
Table 14
2009 Agricultural Energy Services Program Penormance
kWh/Yr Savings 200 (Gross - At Gen) 4,40,442Expenditures $ 807,238Incentives Paid $ 390,597
Program Cost Effectiveness
Levelized Cost ($/kWh)
Lifecycle Revenue Impact ($/kWh)
PTRC
I 0.9470.æ79
$ 0.008636
TRC
0.861
0.æ79
UCT
1.696
0.0497
RIM
0.740
PCT
1.684
Details of 2009 savings by type of measure are provided on the following table.
Table 15
Irrgation Energy Savers kWhlYr Savings by Measure Type (at Site)
Equipment Exchange & Pi\Ot/Linear Upgrade 2,56,171 64%System Design 1,430,178 36%
3,994,349
Major Trends and Activities
On January 1, 2009, program delivery was transferred from the Franklin Soil and Water
Conservation District to Nexant who was selected via a competitive procurement
process in 2008.
The 2009 savings and expenses were 215 percent and 300 percent respectively of the
2008 program savings and expenditures.
During the 2009 calendar year 121 site visits were completed to obtain system
information to be used in either a system consultation evaluation or an energy analysis
evaluation as a part of the Agricultural Energy Services Program. During the same
year, 49 post installation inspections were completed to verify project installation and
energy savings.
24 200910 Annual Report (3_15_10).docx
The following outreach and event activities were completed for the program in 2009:
· Program presentation at the Idaho Irrigation Equipment Association's annual
meeting and expo in Idaho Falls on January 7,2009.
· Set up and operated a booth at the 2009 Agricultural Expo in Pocatello from
January 20th to 22nd, 2009 to meet with customers and provide information about
the program.
· Set up and operated a booth at the Rain For Rent customer appreciation day in
Idaho Falls on February 26th, 2009 to provide program information to customers.
· Gave on site presentations to 11 irrigation dealers in Rexburg, Idaho Falls, Ucon,
Blackfoot, American Falls, Aberdeen, Preston, and Arco with an overview of
program components and the new program manual during the months of April
and May, 2009.
Cost Effectiveness
The 2009 Agricultural Energy Services program is cost effective from a UCT standpoint
however it did not pass the TRC.
Two primary factors contributed to this result; 1) the contribution of onetime and non-
recurring transition costs associated with changing program administrators; and 2)
customer specific costs associated with equipment investments that delivered
operational effciencies in addition to energy efficiency benefits. The simple pre-
incentive pay-back for all 2009 projects completed through the program was 5.7 years
however seven of these projects had simple paybacks of between 15 and 20 years. The
additional customer costs from these seven projects had a 'negative impact on the TRC
results from a strictly electric energy savings perspective. The projects accounted for
about 50 percent of the total customer costs reported by the program and were offset by
utility incentives equal to about 12 percent heavily influencing overall program results.
The Company acknowledges that most customers don't make uneconomic investments
therefore there must be additional benefits beyond just electrical savings that compelled
these customers to proceed with the. projects. While the Company could have
expended additional resources to quantify these non-energy benefits and improve the
test results the Company elected to provide the results using only electric benefits and
reserve a further accounting of the additional customer benefits for the program
evaluation. For any long payback projects such as those described above that are
eligible for incentives, the current program administrator wil take extra steps to align
energy and non-energy benefits with project costs prior to project close-out and
reporting project costs. As a result, this impact on the program's TRC results is not
expected to recur and the program is forecasted to be cost effective under both the TRC
and UCT perspectives in 2010.
Several factors contribute to higher overall forecasted program expenses when
compared with prior program delivery, not the least of which is moving beyond nozzle
exchanges to more complex and expensive project measures. In response to grower
needs the program administrator is providing improved service to irrigation dealers and
25 200910 Annual Report (3_15_10).docx
growers including faster turnaround and increased technical rigor for site work intended
to improve customer service and program performance.
Program Evaluation
In October, 2009, the Company initiated process and impact evaluations for the
Agricultural Energy Services program for program years 2006 - 2008. To acquire the
most accurate impact evaluation information, site visits wil need to be performed when
the irrigation systems are fully operational. As a result, information from this evaluation
wil be available in the third quarter of 2010. Findings from these evaluations wil be key
inputs to on-going program design and modification as well as inputs to future cost
effectiveness determinations.
No process, impact or market impact evaluations were completed on the program
during 2009.
Plans for Next Year
The program administrator has analyzed further changes to this program to increase
prescriptive incentives and better align with other programs, including those of Idaho
Power and the Bonnevile Power Administration. The Company may propose
modifications to the program to include additional promising measures.
Market Transformation - Northwest Energy Efficiency Allance
The Northwest Energy Effciency Allance (NEEA) is a non-profit organization working to
encourage the development and adoption of energy efficient products and services
\through a regional market transformation modeL. NEEA is supported by the region's
electric utilities, public benefits administrators, state governments, public interest groups
and effciency industry representatives.
The Company provides funding for NEEA through a multi-year commitment helping
support their activities in Idaho and Washington. NEEA activities for all sectors are fully
described on their web site at ww.nwallance.org. Rocky Mountain Power expenditures
allocated to Idaho for NEEA in 2009 totaled $287,190. The associated Idaho savings
attributed from the Company's Idaho customers as reported by NEEA for the same
period were 5,914,896 kWh at site.
For the results displayed in the graphical comparisons section, energy savings from
NEEA activities were allocated to customer sectors based on information provided by
NEEA. This allocation is based on region-wide NEEA results by sector. Rocky Mountain
Power's NEEA funding allocated to customer sectors was done in the same ratios as
NEEA's reported energy savings.
In addition to funding, the Company participates in the sector advisory groups, provides
input on NEEA activity effectiveness, and works to coordinate the delivery of NEEA
26 2009 10 Annual Report (3_15_1 O).docx
products and serves with those Qf the Company's programs. The Company continues to
work with NEEA regarding ways to increase their activities and results across all sectors
and in smaller and more rural markets such as Rocky Mountain Power's Idaho service
territory.
Further information about NEEA can be found at the following website
http://ww . nwallance .orgl
Major Trends and Activities
In September 2009, the Northwest Power and Conservation Council released a draft of
the Sixth Power Plan which identified approximately twice the cost effective
conservation potential as that included in the Fifth Power plan. The Sixth Power Plan
identifies NEEA as a key implementer in achieving the higher levels of conservation and
includes NEEA funding by the regional utilties as a specific action item (CONS-3). In
the residential market, NEEA's work in transforming the split system heat pump market
has the potential to help reduce space heating energy use by approximately 200
average megawatts.
Cost-Effectiveness
NEEA has traditionally used a "net market effects" approach to identify savings
attributable to market transformation. This analytical approach estimates utility program
activity and the "baseline" level of market activity. The net difference between these
activities and the total regional activity is attributed to NEEA. Cost effectiveness for the
net market effect savings are assessed from both a total resource and program
administrator perspective. While the company has access to the reported results we do
not directly control the work which is performed at a regional leveL. For these reasons,
the company has traditionally included the NEEA costs and energy savings in reported
results, but does not include these inputs in our portolio level cost effectiveness results.
Program Evaluation
NEEA's approach to evaluations is appropriately more focused on regional changes in
markets instead of site specific installed savings assessments typically identified in local
conservation impact and process evaluations. For these reasons, the company utilizes
NEEA's evaluation of their initiatives and does not attempt to replicates them for a
specific territory.
Plans for Next Year
NEEA's 2010-2014 funding cycle request has been provided to the Company. The
Company is reviewing the request, the plans to increase activity in smaller markets and
its rate impact on Idaho customers.
27 2009 10 Annual Report (3_15_10).docx
Summary of 2009 Results:
Table 16
2009 Revenues (Schedule 191) by
Customer Type
Industrial
SOA.
Public
Strt &
Highway
0%
Table 17
2009 Expenditures (Schedule 191) by
Customer Type
Industral
6%
(Note - Table 17 does not include Irrigation Load Control Service Credits
28 200910 Annual Report (3_15_10).docx
Table 18
2009 Schedule 191 Expenditures by Type
of Program
(Note - Table 18 does not include Irrgation Load Control Service Credits
Table 19
2009 Total Expenditres by Type of
Program
(Note - Table 19 includes Schedule 191 expenditures and Irrgation Load Control Service Credits
29 200910 Annual Report (3_15_10).docx
Table 20
2009 Energy Effciency Expenditures
by Customer Type
Table 21
2009 Energy Effciency Results By
Customer Type
30 200910 Annual Report (3_15_10).doc
Balancing Account Summary
Demand Side Management activities are funded by revenue collected through Schedule
191, Customer Efficiency Services Rate Adjustment charge on customer bils.
Expenses for demand side management expenditures are charged as incurred and
booked to the balancing account. The demand side management balancing account
activity for 2009 is outlined in the table below.
Table 22
Balancing Account Activity 2009 (Schedule 191)
Balance as of 12131/08
$nO,45.84
Monthly Program
Cost - Fixed Carring Accumulated
Assts Rate Recovery Charge Balance
January $593,500.04 $(368,584.62) $1,472.00 $996,838.26
February $247,672.00 $(330,653.18) $1,592.00 $915,449.08
March $293,972.99 $(295,538.43) $1,524.00 $915,407.64
April $860,455.46 $(270,113.24) $15,755.00 $1,521,504.86
May $812,465.90 $(339,685.26) $2,930.00 $1,997,215.50
June $484,589.23 $(490,841.32) $3,323.00 $1,99,286.41
July $578,847.73 $(608,542.13) $3,299.00 $1,967,891.01
August $373,212.18 $(700,049.91) $3,007.00 $1,64,060.28
September $720,006.31 $(522,941,92) $2,904.00 $1,84,028.67
October $626,325.15 $(391,560,70) $3,269.00 $2,082,062.12
November $341,917.49 $(327,278.14) $3,482.00 $2,100,183.47
December $499,720.73 $(36,696.93) $3,613.00 $2,238,820.27
2009 totals $6,432,685.21 $(5,010,485.78) $46,170.00
Column Explanations:
Monthly Program Costs - Fixed Assets: Monthly expenditures for all DSM program activities
Rate Recovery: Revenue collected through Schedule 191, DSM cost adjustment rider.
Carrying Charge: Monthly "interest" charge based on "Accumulated Balance" of the account. The
current "interest rate" for the Accumulated Balance is 2 percent per year.
Accumulated Balance: Current balance of the accunt. A running total of account activities. If
more is collected in "Revenue" than is spent "Monthly Program Costs" for a given month, then the
Accumulated Balance" wil be decreased by the net amount.
At the beginning of 2009, the unfunded balance was approximately $770, 000 and
increased by approximately $1,468,000 during 2009. The unfunded balance at the end
of 2009 is $2.239 milion.
31 200910 Annual Report (3_15_10).doc
Cost Effectiveness:
Introduction
The cost effectiveness of individual programs operated by the Company for 2009 are
calculated using actual expenditures and reported savings. Cost-:effectiveness is
provided at the individual program, load management portolio, residential energy
efficiency portolio, non-residential energy effciency portolio, combined energy
effciency portolio, and overall demand side management program portolio levels.
Deemed savings estimates where applicable were the same as those used in the
planning estimates, unless more recent estimates were available from evaluations.
Energy savings shown in this report are gross savings and the impact of line losses is
indicated with an at "site" or at "generation" designation. Line losses are based on the
Company's 2001 line loss study. Net-to-gross assumptions are consistent with planning
estimates. The energy savings attributed to each program are shaped according to
specific end-use savings (the hourly calculation of when energy is used for the various
end-use measures from which the savings are derived). Program costs and the value of
the energy savings are then compared on a present value basis with the Company's
2008 Integrated Resource Plan (IRP) calculated decrement values for demand-side
resource savings and avoided capacity investments. The energy efficiency resource
decrement values are fully shaped to represent the 8,760 hourly values that exist within
a calendar year. By matching the hourly savings with the hourly avoided costs, both
energy and capacity impacts of energy efficiency savings are recognized.
The costlenefit analysis of the load management programs are based on the avoided
value of peak or capacit investments. For purposes of calculating program cost-
effectiveness no energy savings are included for the load management programs, only
a shift of when the energy is used away from the peak load hours. The five California
Standard Practice Manual cost effectiveness tests were utilized in the cost benefit
analysis for both energy effciency and load management programs. Tables 22 through
33 below provide the cost benefit test results for the 2009 programs. Further details are
available in Appendix 1.
32 200910 Annual Report (3_15_10).doc
Key Assumptions for Cost Effectivenes.s Calculations:
Cost Effectiveness calculations for Programs and Measures (or measure groups) within
each program wil be detailed on the following tables.
Global Assumptions used in all cost effectiveness calculations include:
Table 23
Key Assumptions for All Cost Effectiveness Studies:
Assymptlon
Discount Rate
line losses (Idaho Specific)
Residential
Commercial
Industrial
~
7.40
Soyræ
20081RP
11.389%
10.698%
10.392%
2001 MAC line loss Study
2001 MAC line loss Study
2001 MAC line loss Study
Key elements that go into the cost effectiveness calculation for each program include:
KWIkWh Savings Gross
Administrative Expenses
Incentives Paid
Total Utilty costs - including administration and evaluation
Gross Customer Costs
Net To Gross Ratio
Measure Life
IRP Decrement Value
Please reference Appendix 1, 2009 Cost Effectiveness and Evaluation Details for additional
information on the key assumptions and inputs for cost effectiveness calculations for each
program.
33 200910 Annual Report (3_15_10).docx
Portolio Cost Effectiveness
The overall demand side management portolio and component sectors were all cost
effective on a Total Resource Cost and Utility Cost basis. As expected, only the Load
Control component generated a Ratepayer Impact Test of greater than 1.0.
The following table provides the overall portolio and sector results of all 5 cost
effectiveness tests. (Please refer to the Cost Effectiveness Appendix 1 to this report for
more information on the cost effectiveness tests and the assumptions and inputs).
Table 24
2009 Portolio and Sector Cost Effectiveness Summry
2009 Program Portolio Including Irrigation loa Control
2009 Irrigation Load Control
2009 Energy Effciency Program Portolio
2009 Residential Program Portolio
2009 Non-residential Program Portolio
ICas Effectiveness TestPTRC TRC UCT
3.731 3.392 1.831
5.808 5.280 1.813
1.367 1.242 1.927
1.530 1.391 1.641
1.299 1.181 2.108
RIM
1.470
1.813
0.768
0.694
0.810
PCT
9.734
nJa
3.603
10.737
2.568
Cost Effectiveness Results for each Sector and Program are provided below.
Table 25
2009 Pr p rt Ii In Iu' I' ti Lo d C ntlIt I ~,--
All Measu res
Levelized Slk\'Ì1i Cosls Benefils Net Beneils BeneitCosl
Totl Resuræ Cost Tes (PTRC) + Consevatin Adder $7,167,160 $26,743,767 $19,576,607 3.31
Totl Resuræ Cos Tes (TRC) No Adder $7,167,160 $24,312,516 $17,145,355 3,392
Utili Cos Tesl(UCT)$13,275,355 $24,312,516 $11,037,160 1.831
Rate lf1cl Tes (RIM)$16,537,350 $24,312,516 $7,775,166 1.7
Padpanl Cos Tes (PCT)$1,90,336 $11,587,079 $10,396,743 9,734
Lkycl Revenue Ifl ($/kWi)
Table 26
-
All Measures
Levelized S k\lvl Cosls Benefils Net Beneils BeneitCosl
Total Resræ Cos Tes (PTRC) + Consevation Adder $3,816,417 $22,164,322 $18,347,905 5,808
Totl Resræ Cos Tes (TRC) No Adder $3,816,417 $20,149,384 $16,332,967 5.280
Utili Cos Tes (UCT) $11,114,948 $20,149,384 $9,034,436 1.13
Rate lf1clTes(RIM)$11,114,948 $20,149,384 $9,034,436 1.13
Pananl Cos Tes (PCT)$0 $7,298,531 $7,298,531 nla
Lkycl Revenue lJ!aæ ($/Wi)
34 200910 Annual Report (3_15_10).doc
Table 27
2009 E Em'Pr P rt Ii~,-
All Measures
Level1zed S k\\1i Cosls Beneils ~~et Benenls BeriefitCost
Total Resrce Cos Tes (PTRC) + Conservation Adder 0.0681 $3,350,743 $4,579,445 $1,228,702 1.67
Total Resrce Cos Tes (TRC) No Adder 0.0681 $3,350,743 $4,163,131 $812,389 1.242
Utili CosTes(UCT)0.049 $2,160,407 $4,163,131 $2,002,724 1.927
Raill~actTest(RIM)$5,422,401 $4,163,131 ($1,259,270)0.768
Parlant Cos T est (PCT) $1,190,336 $4,288,548 $3,09,212 3.603
Liicl Revenue I~acl ($JWi)$0.000030233
Table 28
2009 R . de til Pr P rt Ii~ ,
All Measures
Leveiized S klMi Cosls Beneils Net Berieils BelleitCost
Total Resurce Cos Tes (PTRC) + Conseati Adder 0.0675 $988,283 $1,511,639 $523,356 1.53
Total Resrce Cos Tes (TRC) No Adder 0.0675 $988,283 $1,374,217 $385,935 1.391
Uil Cos Tes (UCT) 0.0572 $837,532 $1,374,217 $536,685 1.641
Rail Il1ct Tes (RIM) $1,980,974 $1,374,217 ($606,757)0.694
Pai1nt Co T es(PCT)$150,751 $1,618,585 $1,467,835 10.737
Læcycl Revenue I~acl ($IkWi)$0.000007928
Table 29
2009B me E S' PrI.~
All Measures AC IRP 46'0 LF Decrement
Levelized S'k\\t Cosls Beneils Net Benenls 8enentCost
Total Resurce Cost Tes (PTRC) + Conservatin Adder 0.0616 $723,668 $1,052,066 $328,398 1.54
Total Resurce Cos Test (TRC) No Adder 0.0616 $723,668 $956,424 $232,755 1.322
Utili Cos Test (UCT) 0.0470 $552,666 $956,424 $403,757 1.31
Rate Il1ctTes(RIM)$1,325,391 $956,424 ($368,968)0.722
Parlant Cos Tes (PCT)$17,002 $1,103,461 $932,459 6.453
Liicl Revenue 1"1 ($IkWi)$0.000045779
Table 30
I:,i :-
All Measii res AC I RP 46°'0 LF Decrement
Levelized $/k\M Cosls Benefils Net Benefits BenentCost
Total Resurce Cos Test (PTRC) + Consevati Adder 0.0317 $80,425 $180,651 $100,226 2.246
Total Resrce Cos Test (TRC) No Adder 0.0317 $80,25 $164,228 $83,803 2.042
Utili Cos Tes (UCT) 0.0397 $100,676 $164,228 $63,552 1.631
Rail Il1ct Tes (RIM) $29,904 $164,228 ($126,676)0.565
Parlant Cos Tes (PCT)($20,251)$237,626 $257,878 n/a
Liicl Revenue 1"1 ($JWi)$0.000046624
35 200910 Annual Report (3_15_10).docx
Table 31
2009 Low Income Weathrition
All Measures AC I RP 46% LF Decrement
Levelized $/kV\ti Cosls Beneils Net Beneils BeneitCost
Total Resuræ Cos Tes (PTRC) + Conseation Adder 0.0479 $184,190 $278,922 $94,732 1.514
Total Resuræ Cos Tes (TRC) No Adder 0.0479 $184,190 $253,566 $69,376 1.77
lJli1 Cos Tes (UCT)0.0479 $184,190 $253,566 $69,376 1.377
Rae Iß1act Tes (RIM) $364,678 $253,566 ($111,112)0.695
Partant Co Tes (PCT)$0 $27,498 $27,498 nfa
Lkde Revenue Iß1 ($I)$0.000001096
Table 32
2009 Non-residntl Pr P rf ii,-
All Measures
Levelized $,kli\Cosls Beneils Net Benells BelleltCosl
Total Resuræ Cos Test (PTRC) +Conservaio Adder 0.0717 $2,362,460 $3,067,806 $705,345 1.299
Total Resuræ Cos Tes (TRC) No Adder 0.0717 $2,362,460 $2,788,914 $426,454 1.81
Uili1 Cos Tes (UCT) 0.0402 $1,322,875 $2,788,914 $1,466,039 2.108
Rae Iß1ctTes(RIM)$3,441,428 $2,788,914 ($652,513)0.81
Partant Cos T es (PCT)$1,039,585 $2,669,962 $1,630,377 2.568
Lkde Revenue Iß1ac ($IWi)$0.000021233
Table 33
2009 En Fi~i I ~ ,
All Measures AC I RP 65"/0 LF Decrement
Levelized $ kv\!Cosls Beneils Net Benells BeneitCost
Total Resouræ Cos Tes (PTRC) + Conseatn Adder 0.0378 $502,893 $1,058,318 $555,425 2.104
T ofl Resuræ Cos Tes (TRC) No Adder 0.0378 $502,893 $962,107 $459,214 1.913
Uti CosTes(UCT)0.0251 $333,730 $962,107 $628,377 2.883
Rae Iß1ctTes(RIM)$974,479 $962,107 ($12,372)0.987
Parit Cos T es (PCT) $169,163 $847,899 $678,736 5.012
LÆcl Revenue Iß1ac ($iWi)$0.000002336
Table 34
2009 Fi Ex PrI-
All Measu res AC I RP 65°0 LF Decrement
Levelized $/k\i\Cosls Beneils Net Benells BeneitCost
Total Resuræ CosTesl(PTRC) + Conseatn Adder 0.0577 $379,621 $607,387 $227,766 1.600
Total Resuræ Cos Test (TRC) No Adder 0.0577 $379,621 $552,170 $172,549 1.455
Uti CosTes(UCT)0.0361 $237,527 $552,170 $314,643 2.325
Rae Iß1ctTes(RIM)$744,677 $552,170 ($192,506)0.741
Parlnt Cos Tes (PCT)$142,095 $595,611 $43,517 4.192
Lkde Revenue Iß1c5 ($/kWi)$0.0002419
36 200910 Annual Report (3_15_10).docx
Table 35
. ,~,!:':' ,--
All Measures AC IRP 16% LF Decrement
Levelized $/kWi Cosls Benefils Net Benefils BeneiitrCost
Tolal Resuræ Cost Tes (PTRC) + Conseatin Adder 0.0979 $1,479,946 $1,402,101 ($77,845)0.947
Tolal Resuræ Cos Test (TRC) No Adder 0.0979 $1,479,946 $1,274,637 ($205,309)0.861
Uirit Cos Tes (UCT)0.0497 $751,618 $1,274,637 $523,019 1.696
RaE If1ctTes(RIM),$1,722,272 $1,274,637 ($47,635)0.74
Par1nt Cos Test (PCT)$728,328 $1,226,452 $498,124 1.684
LiÉcl Revenue Illac ($lWi)$0.00004
37 200910 Annual Report (3_15_10).docx
Appendices:
Appendix 1 - Cost Effectiveness and Evaluation Details
Appendix 2 - 2009 Idaho Load Control Program Quantitative Analysis
38 20010 Annual Report (3_15_10).docx
Appendix 1
2009 Cost Effectiveness and Evaluation Details
Cost Effectiveness and Program Evaluation:
The cost effectiveness of individual programs operated by the Company for 2009 are
calculated using actual expenditures and reported savings. Cost-effectiveness is
provided at the individual program, load management portolio, residel)tial energy
efficiency portolio, non-residential energy efficiency portolio, combined energy
efficiency portolio, and overall demand side management program portolio levels.
Deemed savings estimates where applicable were the same as those used in the
planning estimates, unless more recent estimates were available from evaluations.
Energy savings shown in this report are gross savings and the impact of line losses is
indicated through an at "site" or at "generation" designation. Une losses are based on
the Company's 2001 line loss study. Net-to-gross assumptions are consistent with
planning estimates. The energy savings attributed to each program are shaped
according to specific end-use savings (the hourly calculation of when energy is used fC?r
the various end-use measures from which the savings are derived). Program costs and
the value of the energy savings are then compared on a present value basis with the
Company's 2008 Integrated Resource Plan (IRP) calculated decrement values for
demand-side resource savings and avoided capacity investments. The energy
effciency resource decrement values are fully shaped to represent the 8,760 hourly
values that exist within a calendar year. By matching the hourly savings with the hourly
avoided costs, both energy and capacity impacts of energy effciency savings are
recognized. The cost/benefit analysis of the load management programs are based on
the avoided value of peak or capacity investments. For purposes of calculating program
cost-effectiveness no energy savings are included for the load management programs,
only a shif of when the energy is used away from the peak load hours. The five
California Standard Practice Manual cost effectiveness tests were utilized in the cost
benefit analysis for both energy effciency and load management programs.
The Company updates the cost effectiveness results annually based on actual annual
results. Key inputs like net to gross ratios, measure life and deemed savings values wil
be updated as formal evaluations are completed and during the course of normal
maintenance of programs. Company program managers with input from third-part
delivery vendors make determinations about changes to key cost effectiveness inputs.
Any changes wil be noted in future DSM Annual Reports.
In the future, the company intends to complete process and impact evaluations on a two
to three year cycle for each program in the demand side management portolio. Exact
timing and frequency of formal evaluations wil vary depending on maturity of program,
Appendix 1 (3_15_10).docx
experience with the program in other jurisdictions and various other factors including
potential cost of evaluation.
No market effects evaluations were completed on programs in the Company demand
side management portolio during 2009. The Company does plan to update its 2007
Assessment of Long- Term System Wide Potential for Demand Side and Supplemental
Resources during 2010.
Aside from the savings and expenditures associated with the Company's participation in
the Northwest Energy Efficiency Allance (NEEA), the Company does not claim any
savings associated with behavioral changes or market effects in its Idaho jurisdiction.
Company program managers wil review and utilize results and data from NEEA studies
in consideration of program enhancements or modifications.
Further information about NEEA, past and on-going studies and results can be found at
the following website http://ww.nwalliance.org/.
2 Appendix 1 (3_15_10).docx
Key Assumptions for Cost Effectiveness Calculations:
Cost Effectiveness calculations for Programs and Measures (or measure groups) within
each program wil be detailed on the following tables.
Global Assumptions used in all cost effectiveness calculations include:
Key Assumptions for All Cost Effectveness Studies:
Assumption
Discount Rate
Line Losses (Idaho Specific)
Residential
Commercial
Industrial
~
7.4QÆ
Source
20081RP
11.389%
10.698%
10.392%
2001 MAC Line Loss Study
2001 MAC Line Loss Study
2001 MAC Line Loss Study
Key elements that go into the cost effectiveness calculation for each program include:
KWIkWh Savings Gross
Administrative Expenses
Incentives Paid
Total Utility costs - including administration and evaluation
Gross Customer Costs.
Net To Gross Ratio
Measure Life
IRP Decrement Value
The following Tables provide details for the key assumptions and inputs for cost
effectiveness calculations for each program.
3 Appendix 1 (3_15_10).docx
Portolio and Sector Level Cost Effectiveness
The overall DSM portolio and component sectors were all cost effective on a Total
Resource Cost and Utility Cost basis. As expected, only the Load Control component
generated a Ratepayer Impact Test of greater than 1.0.
The following table provides the overall portolio and sector results of all 5 cost
effectiveness tests. (Please refer to the Cost Effectiveness Appendix 1 to this report for
more information on the cost effectiveness tests and the assumptions and inputs).
Table 1
2009 Portolio and Sector Cost Effectiveness Summry
2009 Program Portolio Including Irrigation Load Control
2009 Irrigation Load Control
2009 Energy Effciency Program Portolio
2009 Residential Program Portolio
2009 Non-residential Program Portolio
¡Cost Effectiveness Test
PTRC TRC UCT
3.731 3.392 1.831
5.808 5.280 1.813
1.367 1.242 1.927
1.530 1.391 1.641
1.299 1.181 2.108
RIM
1.470
1.813
0.768
0.694
0.810
PCT
9.734
n/a
3.603
10.737
2.568
Portolio and Segment Level Cost Effectiveness Summaries:
The cost effectiveness results for the portolio level and segment level are aggregations
of the costs and benefits from the component programs. The inputs and assumptions
that support these results are contained in the program level cost effectiveness results.
2009 Pr P rt li In . I' ti Lo d C trl,Iii':,--
All Measures
Levelized S 'kWi Cost Benells Net Benenls BenentCost
Total Resuræ Cos Tes (PTRC) + Conseatin Adder $7,167,160 $26,743,767 $19,576,607 3.731
Total Resuræ Cos Tes (TRC) No Adder $7,167,160 $24,312,516 $17,145,355 3.392
UII CosTes(UCT)$13,275,355 $24,312,516 $11,037,160 1.831
Rate IfTTes(RIM)$16,537,35 $24,312,516 $7,775,166 1.7
Pai1pant Cos Tes (PCT)$1,190,336 $11,587,079 $10,396,743 9.734
licl Revenue Irr ($IkWi)
,-
All Measu res
Levelized S kWi Costs Benelts Net BenenlS BeneltCost
Total Resuræ Cost Test (PTRC) +Conseaion Adder $3,816,17 $22,164,322 $18,347,905 5.808
Totl Resræ COS Tesl (TRC) No Adder $3,816,417 $20,149,384 $16,332,967 5.280
UII Cos Tes (UCT) $11,114,94 $20,149,384 $9,034,436 1.813
Rate IradTes(RIM)$11,114,948 $20,149,384 $9,034,436 1.813
Pai1nl Cos Tes (PCT)$0 $7,298,531 $7,298,531 n/a
licl Revenue Irr ($i)
4 Appendix 1 (3_15_10).docx
2009 En Eft.Pr P rt1i: ' ii
All Measu res
Levelized S/kv\Ai Cost Benells Net Benells BenelvCost
Tolal Resouræ Cos Tes (PTRC) + Consevation Adder 0.0681 $3,350,743 $4,579,445 $1,228,702 1.67
Tolal Resuræ Cos Tes (TRC) No Adder 0.0681 $3,350,743 $4,163,131 $812,389 1.242
Uti CosTes(UCT)0.0439 $2,160,407 $4,163,131 $2,002,724 1.927
Rate lJ1ct Tes (RIM) $5,422,401 $4,163,131 ($1,259,270)0.768
Partcipant Cos Tes (PCT)$1,190,336 $4,288,548 $3,098,212 3.603
Liicyde Revenue Illacl ($JkWl)$0.000030233
2009 R . d til Pr P rt Ii, .
All Measures
Levelized S.k\¡\\Cosls Benefils Net Benefils BeneltCost
Tolal Resuræ Cost Test (PTRC) + Consevatin Adder 0.0675 $988,283 $1,511,639 $523,356 1.53
Tolal Resræ Cos Tes (TRC) No Adder 0.0675 $988,283 $1,374,217 $385,935 1.91
Utilit Cos Tes (UCT) 0.0572 $837,532 $1,374,217 $536,685 1.641
Rate lJ1ct Tes (RIM) $1,980,974 $1,374,217 ($606,757)0.694
Partpant Cos Test (PCT)$150,751 $1,618,585 $1,467,835 10.737
Liicycl Revenue Illacl ($JkWl)$0.000007928
, I'
All Measures
Levelized $/k\¡\\Cost Benells Net Benefils Benefit Cost
Tolal Resouræ Cost Tes (PTRC) + Conseatin Adder 0.071 $2,362,460 $3,067,806 $705,345 1.299
Tolal Resouræ Cos Tes (TRC) No Adder 0.017 $2,362,460 $2,788,914 $426,54 1.81
Utili Cos Tes (UCT) 0.0402 $1,322,875 $2,788,914 $1,46,039 2.108
Rate lJ1ct Tes (RIM) $3,441,428 $2,788,914 ($652,513)0.81
Partpant Cos Tes (PCT)$1,039,585 $2,669,962 $1,630,~77 2.568
Liicycl Revenue Illacl ($JkWi)$0.000021233
5 Appendix 1 (3_15_10).docx
Program Level Cost Effectiveness
Home Energy Savings Program - Schedule 118
The following tables outline the primary inputs and assumptions utilized in the cost
effectiveness calculations for the program.
Program Inputs - Home Energy Savings
Gross kWh/year Savings (at Site)
Program Management and Administration Costs
Incentives
1,349,280 Annual results 200 (Gross at Site)
$ 238,65 Annual costs 20
$ 354,913 Annual costs 20
$ 593,56 Annual costs 20Total utilty Costs
Total Participant Costs
Deemed costs per unit * unit participation. Deemed costs per unit is
$ from a variety of sources, including Regional Technical Forum, Energ673,212 S d i' f" b' d . h' . i' t'
tar an ana ysis a invoices su mitte wit incentive app ica ions
Developed and maintained by progrm administrator - PECI.
Net To Gross Ratio
Planning estimate from original program filing (200) and used for0.8 Iff'prior annua reports cost e ectiveness assessments.
At progra level, it is a weighted average of the measure group
inputs.Measure life
All Measures AC: IRP 46% LF Decrement
Levelized Benefit/Cost
$/kWh Costs Benefits Net Benefits Ratio
Total Resource Cost Test (PTRC)0.0616 $723,668 $1,052,066 $328,398 1.454
+ Conservation Adder
Total Resource Cost Test (TRC)0.0616 $723,668 $956,424 $232,755 1.322
No Adder
Utility Cost Test (UCT)0.0470 $552,666 $956,424 $403,757 1.731
Rate Impact Test (RIM)$1,325,391 $956,424 ($368,968)0.722
Partcipant Cost Test (PCT)$171,002 $1,103,461 $932,459 6.453
LifecycJe Revenue Impact ($/kWh)$0.0005779
Measure Group Inputs and Assumptions:
lighting (Includes CFLs, Fixtures and Ceilng Fans) Value Sourc and Notes
Annual results 20 (Gross at Site) based on measure level savings60,læ from Energy Star savings calculator 200 and RTF PTR Software 200
Allocated percentage (based on kWh contribution) of non -incentive107,2æ .costs for 200.
30,842 Annual costs 20
138,045 Annual costs 20
Deemed based on RTF estimates developed and maintained by122,99 program administrator - PECI.
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs $
$
$
$
Incentives
Total utility Costs
Total Participant Costs
Net To Gross Ratio Planning estimate from original program filing (20) and used for0.8 prior annual reports cost effectiveness assessments.
9 RTF PlR Sofwa Veiion 1.0, FY 207 (10/11200 - 9/301207)
East Side Residential lighting
Measure life (Years)
2001RP Decrement load Shape
6 Appendix 1 (3_15_10).docx
Appliances (Clothes Washers, Dishwasher, Water
Heater, Refrigerar)Value Sourc and Notes
Gross kWh/year Savings (at Site)295,042 Annual results 200 (Gross at Site) based on measure level savings
from RTF PTR Softare 2007
Program Management and Administration Costs $52,185 Allocated percentage (based on kWh contribution) of non -incentive
costs for 200.
Incentives $114,550 Annual costs 20
Total Utility Costs $166,735 Annual costs 20
Total Participant Costs $273,698 Deemed based on RTF and Energ Star estimates developed and
maintained by program administraor- PECI.
Net To Gross Ratio
Planning estimate from original progrm filing (200) and used for0.8. Iff'pnor annua reports cost e ectiveness assessments.
Measure Life (Years)15 Average life for group based on measure level inputs from RTF PTR
Softare Version 1.0, FY'1 (10/1/200 - 9/30/2007)
20IRP Deaement load Shape East Side Residential Whole House
Shell Measures (Insulaton and Windows)Value Sourc and Notes
Annual results 200 (Gross at Site) based on measure level inputs
Gross kWh/Year Savings (at Site)431,396 from RTF PTR Softare Version 1.0, FY'1 (10/1/200-
9/30/2007) +Cool i ng Coeffcient- Research-Gary Smith-200
Progrm Management and Administraion Costs $76,302 Allocated percentage (based on kWh contribution) of non -incentive
costs for 200.
Incentives $190,54 Annual costs 200
Total Utilty Costs $266,84 Annual costs 200
Total Participant Costs $239,992 Windows deemed based on RTF. Insulation is based on application
analysis.
Net To Gross Ratio Planning estimate from original program filing (200) and used for0.8 prior annual reports cost effectiveness assessments.
Measure Life (Years)RTF PTR Softare Version 1.0, FY 200 (10/1/200- 9/30/200)+C00Iing45 Coeffcient-Research-Gary Smith-200
20IRP Decrement load Shape East Side Residential Whole House
HVAC (AC and Heat Pump Equipment, Tune ups,
Proper Installations, Duet Sealing)Value Sourc and Nots
Annual results 20 (Gross at Site) based on measure level inputs
Gross kWh/YearSavings (at Site)16,739 from Quantec Evaluation 200, Research from Energ Trust of Oregon
2007, and RTF PTR Softare Version 1.0 + Research by Gary Smith 200.
Program Management and Administration Costs $2,961 Allocated percentage (based on kWh contribution) of non -incentive
costs for 200.
Incentives $18,975 Annual costs 200
Total Utility Costs $21,936 Annual costs 200
Incremental costs for HVAC measures based on Utah cool cash
Total Participant Costs $36,526 program. Tune-ups & heat pumps - RTF. Duet sealing- PTCS/RTF.
Developed and maintained by progrm administraor- PECI.
Net To Gross Ratio
Planning estimate from original program filing (200) and used for0.8 Iff'prior annua reports cost e eetiveness assessments.
Measure Life (Years)15 Average life. Combination of RTF and Cool Cash
200IRP Decrement load Shape East Side Residential Cooling
7 Appendix 1 (3_15_10).docx
H E s .Me L ie efornene ilY avinas asure eve ost ctienes Input - 2009 Idaho
Measure
Life usdfo2020MeasureGroNetToNETMeasureGroups for
kWh Gr kWh Life 20 Savings Proram
Type Measures Savings Rallo Savings (YealS)Soun:CE Soun: Demils
Clothe Washer-l1er 2-R PTR Sof Verion 1.0, FY 2007
Appliace On 22 0.80 181 14 RTF2 15 (10/1/20 - 9/30207)
Clothes Washer-l1er 2-R PTR So Verion 1.0, FY 207
Appliance Two 250 0.80 20 18 RTF2 15 (10/11200 - 9/302007)2-RT PTR Sof Verion 1.0, FY 207
Appiance Dishwsher 33 0.80 26 9 RTF2 15 (10/1/20 - 9/302007)2-R PTR Sofwa Verion 1.0, FY 207
Appliance Electric Water Heaer 91 0.80 73 10 RTF2 15 (10/1/20 - 9/302007)2-R PTR Sofre Verion 1.0, FY 207
Appliance Referor 98 0.80 78 22 RTF2 15 (10/1/20 - 9/302007)
4-uani20 Evai.. Coin an Ceral
HVAC Ewpoil Co 325 0.80 26 15 Quanec4 15 Air Codilioning Incil Prora: Ewluation
~ PTR Sof Verion 1.0, FY 207
(10/1/20 - 9/3O7)Co Coient-
HVAC CAClHP Tune up 42 0.80 34 5 RTF3 15 Reseah- Smilh-2O
4-uanac-20 Evail Coing an centra
HVAC Ceral Ale Equipment 96 0.80 77 18 Quanec4 15 Air Codilioning Incei.. Prora: ElÆuation
2-RT PTR Sofwa Verion 1.0. FY 207
HVAC Dut Sealing - Elecric 2,150 0.80 1,720 20 RTF2 15 (10/1/20 - 9/302007)
2-R PTR Sofware Verion 1.0, FY 207
HVAC Duct Sealing - Ga 40 0.80 32 20 RTF2 15 (10/1120' 9/302007)
HVAC Hea Pump ColÆion 3,147 0.80 2,518 18 Enery TrustS 15 5-Researh-Energy Trust of Oreon-207
HVAC He Pump Upgrae 811 0.80 649 18 Eney TrustS 15 5-Reseah-Enery Trust of Oreon207
4-uaac-20 Ewpati.. COling and centra
HVAC Pro CAe Intall 23 0.80 18 18 Quanec4 15 Air Codilion Inil Prora: Evaatio
4-an2O Ewpati.. COling an central
HVAC Pro CAe Sizing 67 0.80 54 18 Quanec4 15 Air Coilioing Incil Prora: Ewluaion
Ughting ceilng Fan 107 0.80 86 15 Ene Star'9 1-w.enerystar.govsai calclator-20
2-RT PTR Sof Verion 1.0, FY 207
Lighting Fixture 92 0.80 74 15 RT2 9 (10/1/20 - 9/302007)2-RT PTR Sof Verion 1.0, FY 207
Lighting CFLs 25 0.80 20 9 RTF2 9 (10/1/20 - 9/30/2007)
3-RTF PTR Sofre Verion 1.0, FY 2007
(10/1/20 - 9/3O2oo7)COling Cocient-
Shell Insulation: Attic 0.63 0.80 0.50 45 RT3 45 Reseah-ar Smilh-200
3-RT PTR Sof Verion 1.0, FY 207
(10/1/200 - 9/3O2oo7)+COling Cocien-
Shell Insulation: Floo 0.60 0.80 0.48 45 RT3 45 Reseah-ary Smilh-200
3-RT PTR Sof Verion 1.0, FY 207
(10/1/20 - 9/3O207)COling Cocie-
Shell Inulation: Wall 0.95 0.80 0.76 45 RTF3 45 Reeaar Smilh-2O .
3-RTF PTR Sof Verion 1.0, FY 207-(10/1/20 - 9/3O2oo7)+Coing Cocien-
Shel Window 0.74 0.80 0.59 45 RTF3 45 Reeah-ar Smilh-200
,
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company has
initiated a process and impact evaluation for the program for program years 2006 to
2008. Results of those evaluations are expected to be complete in the second quarter
of 2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
Rocky Mountain Power conducted a competitive bidding process and selected The
Cadmus Group to perform the evaluations. No evaluation expenses were incurred for
this effort in 2009. The Company considers evaluation costs resulting from a
8 Appendix 1 (3_15_10).docx
competitive bidding process to be confidential. The Company wil provide confidential
evaluation cost information to the Commission and Commission Staff under signed
protective agreements.
In the future, the Company intends to complete process and impact evaluations on a
two to three years cycle for each program in the demand side management portolio.
The timing and cycle of evaluations may vary based on maturity of the program,
changes in the marketplace, changes in underlying codes and standards and the
potential cost of evaluation.
9 Appendix 1 (3_15_10).docx
Refrigerator Recycling (See ya later, refrigerator) - Schedule 117
The following tables outline the primary inputs and assumptions utilized in the cost
effectiveness calculations for the program.
Program Inputs - See ya later, refrigerator
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs
957,819 Annual results 20 (Gross at Site)
86,376 Annual costs 20
Incentives
$
$
$ 108,126 Annual costs 20
NA There are no participant costs for this program. .
21,750 Annual costs 20
Total Utility Costs
Total Participant Costs
Net To Gross Ratio Utilze measure specific savings and Net To Gross
Evaluation of Utah Refrigerator Recyding Program - Kema - July 31,82007Measure life (Years)
All Measures AC: IRP 46% LF Decrement
Levelized BenefiCost
$/kWh Costs Benefits Net Benefits Ratio
Total Resouræ Cost Test (PTRC)0.0317 $80,425 $180,651 $100,226 2.246
+ Conservation Adder
Total Resouræ Cost Test (TRC)0.0317 $80,425 $164,228 $83,803 2.042
No Adder
Utility Cost Test (UCT)0.0397 $100,676 $164,228 $63,552 1.631
Rate Impact Test (RIM)$290,904 $164,228 ($126,676)0.565
Partcipant Cost Test (PCT)($20,251)$237,626 $257,878 n/a
Lifecycle Revenue Impact ($/kWh)$0.0000046624
Measure Group Inputs and Assumptions:
Refrigerators
N umber of Units
Value Source and Notes
S66 Annual results 200
Evaluation of Utah Refrigerator Recyding Program - Kema - July 31,
1,149 200
65,334 Annual results 200 (Gross at Site)
Gross kWh/Unit
Gross kWh/year Savings (at Site)
Net To Gross Ratio
Evaluation of Utah Refrigerator Recyding Program - Kema - July 31,0.33200 .
Evaluation of Utah Refrigerator Recyding Program - Kema - July 31,
8200
East Side Residential Whole House
Measure life (Years)
200IRP Decrement Load Shape
10 Appendix 1 (3_15_10).docx
Freezers
Number of Units
Value Sourc and Notes
159 Annual results 200
Evaluation af Utah Refrigerator Recyding Program - Kema - July 31,1,590 200
252,810 Annual results 200 (Gross at Site)
Gross kWh/Unit
Gross kWh/Year Savings (at Site)
Net To Gross Ratio O Evaluatin of Utah Refrigerator Recding Program - Kema - July 31,.58 200
Evaluation of Utah Refrigerator Recding Program . Kema - July 31,8200
East Side Residential Whole House
Measure Ufe (Years)
20IRP Decrement Load Shape
Savings Kits
Number of Units
Value Sourc and Notes
675 Annual results 200
Evaluation of Utah Refngerator Recycling Program - Kema - July 31,81 2007
54,675 Annual results 20 (Gross at Site)
Gross kWh/Unit
Gross kWh/Year savings (at Site)
Net To Gross Ratio 0.73 =uation of Utah Refrigerator Recyding Program - Kema - July 31,
Evaluation of Utah Refrigerator Recyding Program - Kema - July 31,
200. Evaluation indicated 5 year measure life, but with kit savings
8 accounting for only 6% ofthe savings and being generated pnmarily
by eFLs (9yr life), the program was assessed using an overall8year
measure life.
East Side Residential Whole House
Measure Ufe (Years)
20IRP Decrement Load Shape
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company has
initiated a process and impact evaluation for the program for program years 2006 to
2008. Results of those evaluations are expected to be complete in the second quarter
of 2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
Rocky Mountain Power conducted a competitive bidding process and selected The
Cadmus Group to perform the evaluations. No evaluation expenses were incurred for
this effort in 2009. The Company considers evaluation costs resulting from a
competitive bidding process to be confidential. The Company wil provide confidential
evaluation cost information to the Commission and Commission Staff under signed
protective agreements.
In the future, the Company intends to complete process and imp~ct evaluations on a
two to three years cycle for each program in the demand side management portolio.
The timing and cycle of evaluations may vary based on maturity of the program,
changes in the marketplace, changes in underlying codes and standards and the
potential cost of evaluation.
11 Appendix 1 (3_15_10).docx
Low Income Weatherization - Schedule 21
The following tables outline the primary inputs and assumptions utilized in the cost
effectiveness calculations for the program.
Program Inputs - Low Income Weathization
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs $Incentives $Total Utility Costs $
Total Participant Costs
19,919 Annual results 200 (Gross at Site)
29,263 Annual costs 20
168,557 Annual costs 20
197,820 Annual costs 200
NA There are no participant costs forthis program.
Measure Ufe (Years)
1.00 Low income support. NTG assumed to be 1.0
Various Uves By Measure - 200 Quantec Idaho Low Income
30 Weatherization Program Analysis in Support ofTariff Revision
(8/22/05)
East Side Residential Whole House
Net To Gross Ratio
200IRP Decrement Load Shape
All Measures AC: IRP 46% LF Decrement
Levelized Benefit/Cost
$lkWh Costs Benefits Net Benefits Ratio
Total Resource Cost Test (PTRC)0.0479 $184,190 $278,922 $94,732 1.514
+ Conservation Adder
Total Resource Cost Test (TRC)0.0479 $184,190 $253,566 $69,376 1.377
No Adder
Utility Cost Test (UCT)0.0479 $184,190 $253,566 $69,376 1.377
Rate Impact Test (RIM)$364,678 $253,566 ($111,112)0.695
Participant Cost Test (PCT)$0 $277,498 $277,498 n/a
Lifecycle Revenue Impacts ($/kWh)$0.0000010946
Measure Group Inputs and Assumptions:
k hW SavinRS. Measures Kwh Savings Source
IMtieriziJn 200 Quantec Idaho Low Income Weatherization Program Analysis in
2,153 Support ofTariff Revision (8/22/05)
CFLs (nurr of households) 200 Quantec Idaho Low Income Weatherization Program Analysis in
54.8 Support ofTariff Revision (8/22/05)
Retigerabrs 200 Quantec Idaho Low Income Weatherization Program Analysis in
1,5il Support ofTariff Revision (8/22/05)
Hot W3Ðr Meare 200 Quantec Idaho Low Incoe Weatherization Program Analysis in
397 Support of Tariff Revision (8/22/05)
12 Appendix 1 (3_15_10).docx
Measure Ufe
Measure Economic Ufe - Measures Years)Souræ
Vlalierizfin 200 Quantec Idaho Low Income Weatherization Program Analysis in
30 Support of Tariff Revision (8/22C1)
CFLs (nuiir of househols) 200 Quantec Idaho Low Income Weatherization Program Analysis in
9 Support ofTariff Revision (8/22C1)
Retgatirs 200 Quantec Idaho Low Income Weatherization Program Analysis in
19 Support ofTariff Revision (8/22/C1)
Hot Waer Measre 200 Quantec Idaho Low Income Weatherization Program Analysis in
9 Support of Tariff Revision (8/22/C1)
Initial Planning Assumptions and analysis
completed in 2005
Cost Effectiveness Analysis completed in
2006
2005 Quantec Idaho Low Income Weatherization
Program Analysis in Support of Tarif Revision
(8/22/05)
Idaho Low Income Program Cost Effectiveness
Analysis - Quantec August 30, 2006.
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company intends
to conduct a program evaluation during 2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
13 Appendix 1 (3_15_10).docx
Energy FinAnswer - Schedule 125
The following tables outline the primary inputs and assumptions utiJzed in the cost
effectiveness calculations for the program.
Program Inputs. Energy FinAnswer
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs
Incentives
1,494,547 Annual results 20 (Gross at Site)
$ 207,192 Annual costs 200
$ 151,234 Annual costs 200
$ 358,426 Annual costs 20
$ 416,144 Incrmental costs incurred by consumers based on receipts provided.
Total Utilty Costs
Total Participant Costs
Net To Gross Ratio
Planning estimate from program inception Energy FinAnswer Market
080 Assessment/or PacifiCorp's Idaho Service Territory Preliminary. Findings - Nexant, May 25, 200. DEER All Other Residential Programs,
200.
Energy FinAnswer Market Assessment/or PacifiCorp's Idaho Service
15 Terriory Preliminary Findings - Nexant, May 25, 2005. Consistent with
experience in other markets.
East Side System
Measure Ufe (Years)
200IRP Decrement load Shape
Savings Calculations and Reporting:
Savings reported for the Energy FinAnswer program are based on project and measure
specific verified savings. Preliminary engineering savings and costs estimates are
completed during project scoping by a pre-qualified third part energy engineering firm
working under contract with the company. Savings and costs are further refined into an
energy analysis completed by the same firm. Once the customer installs and
commissions (if required) the project, a post-installation inspection is conducted and the
savings are re-calculated for each project. Incentives are then paid on final inspected
savings amounts.
Measure costs are gathered from customer invoices.
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company has
initiated a process and impact evaluation for the program for program year 2008.
Results of those evaluations are expected to be complete in the second quarter of 2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
Rocky Mountain Power conducted a competitive bidding process and selected The
Cadmus Group to perform the evaluations. No evaluation expenses were incurred for
this effort in 2009. The Company considers evaluation costs resulting from a
competitive bidding process to be confidentiaL. The Company wil provide confidential
14 Appendix 1 (3_15_10).docx
evaluation cost information to the Commission and Commission Staff under signed
protective agreements.
In the future, the Company intends to complete process and impact evaluations on a
two to three years cycle for each program in the demand side management portolio.
The timing and cycle of evaluations may vary based on maturity of the program,
changes in the marketplace, changes in underlying codes and standards and the
potential cost of evaluation.
15 Appendix 1 (3_15_10).docx
FinAnswer Express - Schedule 115
The following tables outline the primary inputs and assumptions utilized in the cost
effectiveness calculations for the program.
Program Inputs - FinAnswer Express
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs
Incentives
838,395 Annual results 200 (Gross at Site)
$ 173,784 Annual costs 200
$ 81,320 Annual costs 200
$ 255,104 Annual costs 20
Actual customer costs incurrd based on project dose-out
$ 243,676 documentation (invoices) - less any adjustments (if necessary) for
baseline equipment.
Total Utility Costs
Total Participant Costs
Net To Gross Ratio
Planning estimate from program inception (200) . FinAnswer Express
0.96 Market potential Assessment for PacifiCorp's Idaho Service Territory-
Nexant, August 22, 200.
Measure Ufe
FinAnswer Express Market characterization for PaciiCorp's Idaho
Service Territory - Nexant, August 22, 200 which used 15 years13 overalL. Ufe shortened to 13 year on program basis to accunt for
some measures such as occupancy sensors with shorter life.
(Note: For cost effectiveness, Total Utility Costs were adjusted by ($8,800) to account for incentives
booked to the balancing accunt that were not associated with 2009 savings)
All Measures AC: IRP 65% LF Decrement
Levelized BenefltJCost
$/kWh Costs Benefits Net Benefits Ratio
Total Resouræ Cost Test (PTRC)0.0577 $379,621 $607,387 $227,766 1.600
+ Conservation Adder
Total Resouræ Cost Test (TRC)0.0577 $379,621 $552,170 $172,549 1.455
No Adder .
Utiity Cost Test (UCT)0.0361 $237,527 $552,170 $314,643 2.325
Rate Impact Test (RIM)$744,677 $552,170 ($192,506)0.741
Participant Cost Test (PCT)$142,095 $595,611 $453,517 4.192
Ufecycle Revenue Impact ($/kWh)$0.0000042419
16 Appendix 1 (3_15_10).docx
Measure Group Inputs and Assumptions:
Ughting
Gross kWh/year Savings (at Site)
Value Sourc and Notes
748,891 Annual results 20 (Gross at Site)
$ 155,231 Allocated percentage (based on kWh contribution) of non -incentivecosts for 20.
$ 71,595 Annual costs 20
$ 226,826 Annual costs 20
Retrofit lighting costs are based on actual customer costs. New
$ 228,259 construction lighting costs are deemed based on a combination of
vendor surveys and third part data.
Program Management and Administration Costs
Incentives
Total Utilty Costs
Total Participant Costs
Net To Gross Ratio
FinAnswer Express Market potential Assessment for PacifiCorp's Idaho0.96 Service Territory - Nexant, August 22, 2005.
FinAnswer Express Market characterization for PaciiCorp's Idaho
13 Service Terriory - Nexant, August 22, 200 which used 15 yearsoveralL. Ufe shortened to 13 year on progrm basis to accunt for
some measures such as occupancy sensors with shorter life.
East Side Commercial Ughting
Measure Ufe (Years)
200IRP Decrement Load Shape
Non-Ughting
Gross kWh/year Savings (at Site)
Value Source and Notes
89,50 Annual results 200 (Gross at Site)
$ 18,553 Allocated percentage (based on kWh contribution) of non -incentivecosts for 200.
$ 9,725 Annual costs 200
$ 28,278 Annual costs 20
Measures receiving custom incentives are actual costs. Motors and
$ 15,417 HVAC are deemed costs from a combination of vendors and third
part data. - verify with Nexant.
Program Management and Administration Costs
Incentives
Total Utilty Costs
Total Participant Costs
Net To Gross Ratio FinAnswer Express Market potential Assessmentfor PacifiCorp's Idaho0.96 Service Territory. Nexant, August 22, 200.
Measure Ufe (Years)
FinAnswer Expres Market characterization for PadfiCorp's Idaho
Service Territory - Nexant, August 22, 200 which used -15 years13 overalL. Ufe shortened to 13 year on progrm basis to account for
some measures such as occupancy sensors with shorter life.
2O1RP DecrmenUoad Shape East Side System
Cost Effectiveness Inputs at the Measure level:
The FinAnswer Express program includes savings estimates values for a wide range of
prescriptive measures including lighting, motors, HVAC equipment, and shell measures.
In addition, the program includes a provision to calculate a custom incentive for
measures without a prescriptive incentive.
The basis for the savings estimates for this program is the FinAnswer Express Market
Potential Assessment for PacifiCorp's Idaho Service Terrtory, dated August 22,2005
and prepared by Nexant, Inc. This document was provided in the original 2005 program
filing.
17 Appendix 1 (3_15_10).do
The savings estimates from the Nexant work are the basis for several savings
calculations tools used to manage the Idaho FinAnswer Express program. Lighting
savings contributed approximately 90% of the program results in 2009. The lighting tool
is an Excel based tool built and maintained by the program staff that includes deemed
wattages by fixture types for both baseline and replacement fixtures. Baseline (pre) and
post fixture counts along with hours of operation are input on a project specific basis.
For each project, the lighting tool calculates energy and average demand savings,
incentives, the value of energy and demand savings, simple paybacks with and without
incentives, counts of replaced fixture by type and several other project specific metrics.
Savings from NEMA premium motors are calculated using a spreadsheet based tool
referencing deemed energy and capacity values based on horsepower size and sector
(i.e., commercial and industrial). These values are derived from efficiency gains and
operating hour assumptions.
Savings from mechanical and other energy effciency measures are calculated in a
manner similar to motors.
Cost effectiveness inputs included in this section are the aggregations of savings and
expenditures in two large categories - lighting and non-lighting.
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company has
initiated a process and impact evaluation for the program for program years 2006 to
2008. Results of those evaluations are expected to be complete in the second quarter
of 2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
Rocky Mountain Power conducted a competitive bidding process and selected The
Cadmus Group to perform the evaluations. No evaluation expenses were incurred for
this effort in 2009. The Company considers evaluation costs resulting from a
competitive bidding process to be confidentiaL. The Company wil provide confidential
evaluation cost information to the Commission and Commission Staff under signèd
protective agreements.
In the future, the Company intends to complete process and impact evaluations on a
two to three years cycle for each program in the demand side management portolio.
The timing and cycle of evaluations may vary based on maturity of the program,
changes in the marketplace, changes in underlying codes and standards and the
potential cost of evaluation.
18 Appendix 1 (3_15_10).docx
Agricultural Energy Services (Irrigation Energy Savers) - Schedule 155
The following tables outline the primary inputs and assumptions utilized in the cost
effectiveness calculations for the program.
Agricultural Energy Services (Irrigation Energy Savers)
Gross kWh/Year Savings (at Site) 3,99,349 Annual results 20 (Gross at Site)
Program Management and Administration Costs $ 416,641 Annual costs 20
Incentives $ 390,597 Annual costs 20
Total Utilty Costs $ 807,238 Annual costs 200
$ Combination of deemed and actual costs depending on the measureTotal Participant Costs 1,437,654
type.
Net To Gross Ratio Review and Deelopment of Utah Power's Irrigation Program /n Idaho0.75 . .. 3 200
Fazio Engineering, August 1, .
At program level, it is a weighted average of the measure group
inputs.Measure Ufe
All Measures AC: IRP 16% LF Decrement
Levelized BenefltlCost
$/kWh Costs Benefits Net Benefits Ralio
Total Resource Cost Test (PTRC)0.0979 $1,479,946 $1,271,470 ($208,476)0.859
+ Conservation Adder
Total Resource Cost Test (TRC)0.0979 $1,479,946 $1,155,881 ($324,064)0.781
No Adder
Utility Cost Test (UCT)0.0497 $751,618 $1,155,881 $404,263 1.538
Rate Impact Test (RIM)$1,722,272 $1,155,881 ($566,391)0.671
Participant Cost Test (PCT)$728,328 $1,112,186 $383,858 1.527
Lifecycle Revenue Impacts ($/kWh)$0.0000124803
Equipment Exchange and Pivot/inear Upgrdes
Gross kWh/Year Savings (at Site)
Program Management and Administraion Costs
Value Sourc and Notes
2,564,171 Annual results 200 (Gross at Site)
$ 267,46 Allocated percntage (based on kWh contribution) of non -incentivecosts for 20.
$ 20,923 Annual costs 20
$ 471,386 Annual costs 20
Combination of deemed measure costs based on Fazio work and
$ 416,144 actual customer costs submitted with applications- verify with
Nexant.
Incentives
Total Utility Costs
Total Participant Costs
Net To Gross Ratio Review and Development of Utah Power's Irrigation Program In Idaho0.75 . .. 3 20Fazio Engineering, August 1, .
Review and Development of Utah Power's Irrigation Program In Idaho4 Fazio Engineering, August 31,20.
East Side Commercial Cooling
Measure Ufe (Years)
20IRP Decrment load Shape
19 Appendix 1 (3_15_10).docx
System Upgrades
Gross kWh/Year Savings (at Site)
Program Management and Administration Costs
Value Sourc and Notes
1,430,178 Annual results 200 (Gross at Site)
$ 149,178 Allocated percentage (based on kWh contribution) of non -incentivecosts for 20.
$ 186,674 Annual costs 20
$ 335,852 Annual costs 200
Actual customer costs incurred based on project dose-out
$ 1,021,510 documentation (invoices)- less any adjustments (if necessary) for
baseline equipment.
Incentives
Total Utility Costs
Total Participant Costs
Net To Gross Ratio Review and Development of Utah Power's Irrigation Program In Idaho0.75 . .. 200Fazio Engineering, August 31,. .
Review and Development of Utah Power's Irrigation Program In Idaho
Fazio Engineering, August 31,200. Planning value was 7 years. Based
on project types receiving incentives in this category - major
equipment, piping and variable frequency drives which are similar in12 type and measure life to Energ FinAnswer, the measure life for
these measures was adjusted to an approximate mid-point between 7
years and 15 years (Energy FinAnswer measure life) and was set at 12
years.
East Side Cornmerdal Cooling
Measure Ufe (Years)
200IRP Decrement Load Shape
Cost Effectiveness Inputs at the Measure Level:
Measure level savings estimates for prescriptive measures for the Irrigation Energy
Savers program are based on the Review and Development of Utah Power's Irrgation
Program in Idaho, prepared by Fazio Engineering on August 31, 2005.
For projects that are not eligible for prescriptive incentive, savings are estimated at the
site utilizing program funded engineering.
The Company aggregates savings and incentives for reporting at the program level.
Cost effectiveness inputs included in this section are the aggregations of savings and
expenditures in two large categories - Equipment Exchange and Pivot/Linear Upgrades
(including nozzles, gaskets, drains, and pivot/linear equipment upgrades) and System
Upgrades (including system analysis). These groupings are utilized to reflect similar
measure lives.
Cost Effectiveness Results:
For discussion of the cost effectiveness results for the program and recommendations
for potential modifications, please see Agricultural Energy Services program section in
the body of the Idaho DSM Annual Report.
Process and Impact Evaluation
No process or impact evaluations were completed during 2009. The Company has
initiated a process and impact evaluation for the program for program years 2006 to
20 AppendiX 1 (3_15_10).docx
2008. Results of those evaluations are expected to be complete in the third quarter of
2010.
The Company did not make any program modifications as a result of process or impact
evaluations during 2009.
Rocky Mountain Power conducted a competitive bidding process and selected The
Cadmus Group to perform the evaluations. No evaluation expenses were incurred for
this effort in 2009. The Company considers evaluation costs resulting from a
competitive bidding process to be confidentiaL. The Company wil provide confidential
evaluation cost information to the Commission and Commission Staff under signed
protective agreements.
In the future, the Company intends to complete process and impact evaluations on a
two to three years cycle for each program in the demand side management portolio.
The timing and cycle of evaluations may vary based on maturity of the program,
changes in the marketplace, changes in underlying codes and standards and the
potential cost of evaluation.
21 Appendix 1 (3_15_10).docx
Irrigation Load Control Program - Schedules 72 and 72A
The following tables outline the primary inputs and assumptions utilzed in the cost
effectiveness calculations for the program.
Program Inputs - Irrigation Load Control
Total kW Under Load Control (All contracts)
Benefit Value of Dispatched kW (At Site)
Value Source and Notes
258,355 2001D Load Control Quantitative Review
200 calculation based on Average Dispatch247,050 (consistent with incentive calculation) - cadmus 200
200 Value as determined by agreed upon Valuation73.09 Methodology (see notes below) - 2001RP
81.56 2001RP Value Grossed up for 10.392% line losses
$
$
Average kW Dispatched during irrigation season (At Site)
Benefit Value of Dispatched kW (At Generation)
Benefit Value = Avg kW Distpatched multiplied by $81.56 $20,149,38 Calculation ($81.56 $/kW * 247,050 kW-Yr)
Program Management and Administration Costs $
$
$
3,816,417 Annual costs 200
Annual costs 200 - less $25,94 of 200 incentives7,298,531 'd' 200
pai In
11,114,94 Annual costs 200
NA There are no direct participant costs for the program.
Incentives
Total Utilty Costs
Total Participant Costs
Net To Gross Ratio 1.00 Assume 1.0 NetTo Gross
Benefit value is NPV of 10 year benfis from avoided10 i;eneration and market purchases.Measure life (Years)
Notes:
For further background on 200 program perfromance see "200ID Irrigation Quantitative Review.doc" dated November 14, 200
For further background on the valuation methodology, please refer to "Proposed Valuation Methodology for the Idaho
Irrigation load Control Program" that was produced as part of a stipulated settlement with the Idaho Irrigation
Pumpers' Association on Nov. 5, 2007.
':.
All Measures
I Levelized S kVvt Cosls Beneils Net Be"efits Benefit Cos:
Toml Resuræ Cos Test (PTRC) + Conservaion Adder $3,816,417 $22,164,322 $18,347,905 5.808
Toml Resuræ Cos Tes (TRC) No Adder $3,816,417 $20,149,384 $16,332,967 5.280
Uil CostTes(UCT)$11,114,94 $20,149,384 $9,034,43 1.813
Raæ Il1ctTes(RIM)$11,114,948 $20,149,38 $9,034,436 1.813
Pancant Cos Tes (PCT)$0 $7.298,531 $7,298,531 n/a
liicl Revenue Il1act ($lWi)
Reporting Period Changes
Please note that the costs included in this DSM Annual Report and the tables above
reflect cost associated with the Calendar Year 2009, while the costs included in the
2009 10 Irrgation Quantitative Review reflect costs for the Seasonal Report that runs
from October 1, 2008 to September 30, 2009. Operational results and savings are
consistent between reports because the load control season occurs during June
through August of each year.
22 Appendix 1 (3_15_10).docx
Therefore, results included in this Annual Report reflect the operations/savings and
costs for the Calendar year 2009. Cost Effectiveness was reevaluated to reflect the
difference in period costs. For calculation of cost effectiveness, program incentive
expenses were reduced by $25,946 to reflect incentive payments made during calendar
year 2009 for 2008 program participation.
Program costs reflected in this annual report are $460,284 higher than those reflected in
the 2009 10 Irrgation Quantitative Review, while the operational results and associated
savings and benefits are identical between reports. As a result, the cost effectiveness
test results are slightly lower in this annual report than those reported in the 2009 10
Irrgation Quantitative Review.
Beginning in Calendar Year 2010, the Idaho Irrgation Load Control Report (or 10
Irrgation Quantitative Review) wil reflect calendar year results and. costs and wil be
included with the 2010 DSM Annual Report.
Cost Effectiveness Inputs
Program kW savings are calculated based on the aggregation of individual meters with
load control equipment (both scheduled and dispatchable). Savings per meter are
calculated as average irrigation usage over the past 24 months. Curtailments/dispatch
events are logged to indentify all meters that were dispatched during an event to
develop the total amount dispatched.
For benefit determination, The Cadmus Group utilizes a simplified excel model to
develop a weighted average monthly dispatch for the irrigation season (247,050 kW for
2009). This amount is then multiplied by the value per kW as determined by the
Proposed Valuation Methodology for the Idaho Irrgation Load Control Program dated
November 5,2007. The value for 2009 is $73.09/kW-yr at site, or $81.56/kW-yr at
generation including 10.392% line losses.
Program Evaluation
Rocky Mountain Power has provided an annual report (or 10 Irrgation Quantitative
Review) of the activities and results of the Idaho Irrigation Load Control Program to the
Idaho Commission each year since the program started in 2003. These results reflect
the measured actual dispatch and impact on the system. The annual reporting
approach utilzes a workplan similar to those used by third part evaluation firms and
serves as an annual program evaluation.
23 Appendix 1 (3_15_10).docx
Appendix 2
2009 Idaho Irrigation Load Control Quantitative Review, November 14,2009
Reporting Period Changes
The 2009 Idaho Irrigation Load Control Quantitative Review reflects
program expenditures and program operations and benefits for the period
from October 1, 2008 to September 30, 2009.
The costs included in the Demand Side Management Annual Report
reflect costs associated with the Calendar Year 2009. Operational results
and savings are consistent between reports because the load control
season occurs during June through August of each year. Therefore,
results included in the Demand Side Management Annual Report reflect
the operations/savings and costs for the Calendar Year 2009. Cost
Effectiveness was reevaluated to reflect the difference in period costs and
details are included in the Cost Effectiveness section of this report.
Program costs reflected in the Demand Side Management Annual Report
are $460,284 higher than those reflected in the 2009 Idaho Irrigation Load
Control Quantitative Review, while the operational results and associated
savings and benefits are identical between reports. As a result, the cost
effectiveness test results are slightly lower in the Demand Side
Management Annual Report than those reported in the 2009 Idaho
Irrigation Load Control Quantitative Review.
For consistency and to improve reporting efficiency, beginning in Calendar
Year 2010, the Idaho Irrigation Load Control Report (or Idaho Irrigation
Load Control Quantitative Review) will reflect calendar year results and
costs, and it wil be included with the filing of this Demand Side
Management Annual Report.
A DIVISION OF PACIFICORP
ATTACHMENT 2
Schedule 72 & 72A Idaho Irrigation
Load Control Programs
2009 Idaho Irrigation Load Control Quantitative Review
14 November 2009
Table of Contents
Page
Report Organization ......................................................................................................................................................1
Background .........................................................;.........................................................................................................1
2009 Schedule 72 (Scheduled Forward) Resu/ts.......................................................................................................... 1
Table Two Longitudinal and Current Year Scheduled 72 Partcipation Credits by Month ...........................................2
Table Three Longitudinal and Current Year Scheduled 72 Participation Credits Issued............................................. 2
Table Four Comparative Scheduled 72 & 72A Costs 2003, 2004 & 2005................................................................... 2
Table Five Schedule 72 Program Impacts by Participation Option.............................................................................. 3
Table Six Schedule 72 2009 Avoided kW by Month, Monday Control Day & Hour..................................................... 4
Table Seven Schedule 72 2009 Avoided kW by Month, Tuesday Control Day & Hour............................................... 4
Table Eight Schedule 72 2009 Avoided kW by Month, Wednesday Control Day & Hour............................................ 5
Table Nine Schedule 72 2009 Avoided kW by Month, Thursday Control Day & Hour ................................................5
Cost-effectiveness analyses .... .... ... ........ ................................... ..................... .......... ... ...... ............ .... ........ ......... ...... ....6
Table Ten 2009 Benefit I Cost Categories & Values-Schedule 72............................................................................. 6
Table Eleven 2009 Cost-effectiveness Analyses-Schedule 72 ..................................................................................7
Measurement & Verification (M&V) processes ............................................................................................................. 7
2009 Schedule 72A (Dispatch) Resu/ts......................................................................................................................... 8
Customer Opt-Outs...................................................................................................................... ................................. 8
Table Thirteen Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch EvenL..........................8
Dispatch Events ............................................................................................................................................................8
Table Fourteen Dispatch Program Only Nominal Load (kW) Impacts x Dispatch Event .............................................. 9
Table Fifteen Dispatch Program Only Net Load (kW) Impacts x Dispatch EvenL..................................................... 9
Cost-effectiveness analyses ......................................................................................................................................... 9
Table Sixteen 2009 Benefit I Cost Categories & Values-Schedule 72A...................................................................10
Table Seventeen 2009 Cost-effectiveness Analyses.................................................................................................10
2009 Schedule 72 & Schedule 72A Results.......................................................... ................ .............. ........................ 11
Avoided demand.........................................................................................................................................................11
Table Eighteen Program Impacts by Participation Option .........................................................................................11
Table Twenty 2009 Dispatch Events & Associated Net Avoided kW (Schedule 72 & Schedule 72A) ......................12
Table Twenty-One Hourly Load impacts Entire 2009 Program Season ....................................................................12
\Table Twenty-One Hourly Load impacts Entire 2009 Program Season ................................................................... 13
Table Twenty-One (cont.) Hourly Load impacts Entire 2009 Program Season .........................................................14
Table Twenty-One (cont.) Hourly Load impacts Entire 2009 Program Season .........................................................15
Load profile data impact analysis................................................................................................................................16
Cost-effectiveness analyses .......................................................................................................................................16
Table Twenty-three 2009 Cost-effectiveness Analyses................................................... ........................ ............. ..... 17
Conclusions..................................................................................................................... ............................................ 17
Recommendations ......................................................................................................................................................18
Attachment One ..........................................................................................................................................................19
ii
Report Organization
Idaho Public Utilities Commission Order No. 29209 and Order No. 29416 in Case No. PAC-E-03-14 requires Rocky
Mountain Power (the Company), a division of PacifiCorp, prepare an annual report on the Idaho Irrigation Load
Control Program (Program). In 2007, and as approved by the Commission in Order No. 30243, Rocky Mountain
Power (RMP) initiated a Dispatch irrigation pilot program (SChedule 72A) evaluating the effcacy of a 2-way control
technology unique to the irrigation industry. This report presents quantitative results on Schedule 72 and SChedule
72A as required by the Commission order. The SChedule 72A assessment wil follow the standard report. Summary
statistics from both Schedule 72 and Schedule 72A wil be combined and presented. Recommendations and
Conclusions wil be presented. All costs are accrued for the 2009 program year (1 October 2008 through 31
September 2009) with the exception of participation credits. Unless otherwise noted, data are calculated as of 19
October 2009.
Background
Reporting requirements include responses to the following:
1. The number of irrigation customers who were eligible to participate in the Program
2. The number of irrigation customers who entered into a load control Service Agreement
3. The number of irrigation customers who participated in the Program for the full three and one-half months
4. The number of irrigation customers who are not eligible to participate in the following year's Program
5. The total dollar amount of credits provided under the Program identified by month
6. Proposed changes andlor recommendations to improve the Program
2009 Schedule 72 (Scheduled Forward) Results
Table One
Longitudinal and Current Year Scheduled 72 Eligible & Full-Year Participating Sites & Customers
2003 Actual Participants
2004 Actual Participants
2005 Actual Participants
2006 Actual Participants
2007 Actual Participants
2008 Actual Participants
2009 Actual Participants
Eligible 2009 Counts
Customers NOT eligible to participate 2009
Participant Sites
401
734
1,065
931
681
87
123
4,723
N/A
Participant Customers
207
340
489
478
405
79
112
2,032
o
2009 Idaho Irrgation Load Control Quantitatie Review Page 1
Table Two
Longitudinal and Current Year Scheduled 72 Participation Credits by Month
Standard Credits
kW Under Contract
Total Credits
June
$13,401.88
S,887.01
$43,912.27
July
$14,140.39
4,204.0
August
$13,349.S6
4,1S1.0
September
$3,020.44
3,344.0
Note: avoided kW is as of the day of creit issuance
Table Three
Longitudinal and Current Year Scheduled 72 Participation Credits Issued
Year Total Participation Credits Issued
2003 $277,S83.72
2004 $410,32S.49
200S $842,666.80
2006 $92S,S7733
2007 $684,924.98
2008 $30,680.65
2009 $43,912.27
Table Four
Comparative Scheduled 72 & 72A Costs 2003, 2004 & 2005
2003 Costs 2004 Costs 200S Costs
Cost Category (April '03-Sept '03) Oct '03-Sept '04 Oct '04-Sept 'OS
_A~~i~i~.tr~tiY~_~~EP.~ ..._..______~9.!.?.~~:.~~....""""""""""",,.,,""~~ ,665.:?e...,,""""""""""s~?~,,:.??.,,""""
.".p.r~~r~r!L~"_~u_~ti?n"..___.._______"" """g.~,,~.~:.~~ $8,3.eeß.~"""""""""". .. ... S~A?Q.gQ"""""".,,
Field.Leg~!e.'.P~"~.~.~~~~~~p.~n~~.~.".....g~Q!.?~!..98_",,"""" $?3e.~~Q?.:.Q~""""""" ...~~??!.Q?..~,,:.Q.~""
"""p..~.~!?!.e~!i?~gr.~~.i!~._E!.!.,§_a.~J2 _ .. .""""~.i.~.Q.~~??,49.""",,,,"""~~~.?!???.:a.g
Prog'.~'."~~n~~~~~nt..".....".""..,,"""""___~~Q!e_?:.e~,,._.._._.__.___.~§?,O~?:.?e""""""s?~,.~??.:?._e_
"""R~e?~i~~...""..._._..~_~?~.:?._e_____.___~eiQ:.QQ".,,_._.._"""""""""_.!Q:QQ_.__.,,"""
"""""""""""""""""""""""TC!t.~!"P.rC!~r~'.,,9.9.~.t.~""""""" $SSQ~eQ.Q:.~~.__"".__,,_E~!.!.1i~:e~_._____.___J~,_??~?3e:Q?"__."",,
Note: 2003 costs over 6 month period; subsequent Program-year costs are calculated over a 12 month period
1 Throughout this report and in all cases avoid demand values are reported at the site and are NOT grossed-up for generation thereby taking into
accuntT&D losses.
2009 Idaho Irrgation Load Control Quantitative Review Page 2
Table Four (cont)
Comparative Load Control Program Costs 2006, 2007 & 2008
2006 Costs 2007 Costs 2008 Costs
Cost Category Oct 'OS-Sept '06 Oct 'OS-Sept '06 Oct '07 -Sept '08
,,_~~_f!J~i,~,tr~,tiY~,,~~P29_~,_,. $194,60 ..''''''''''''''''''''''~,~!SOO:qQ,'''''''''''''''''''".,.... ....~,~,!,e~Q,:,?Q,,"""""
..t.'!~!.~'.~~~'.~t~~._ .""___"""",,,~,1,!,,~,?,S,00 . ..,"""""""""S2,268: 7S",,,,,,,"""""__,,.,,.. s?,!,?ea,:.?_____""..
Fiel~ / Eq~~p / ~~_~~,~!~:.e2'P.~~~_es"_,,s_aaQ!,aQ?.:Q~,_ ""J!.~!.!,ee~ß,?____'" .. ..J,?!,a,~,e,!,aa6.26 .
___~,~,~!~ip~ti,?~,,~,r.~~,it~___,,__._ ."...,._J~§,S7!.:_~~ .,""__~,!~?g~aQ:~ 7S,?!e9~,ae~,:,??
p.'!!lr~'.~~n~~~,~~nt ________"'''''''''___'''''''_____ ,~~,?!,??~,:,~_~__"______!~9.!.,!~~:9g_",_,, ,__,__,,,,~e~!9?1ie__,,,___
""R~p?,~i~9.,_,,,"________________________________________,,_______________SQ:QQ__,,___...._...._____ ______""'~Q:Q~_____,,___,____JO,OQ____,_"_'"
""'"""------ ______"_r9.t~'.f'.'.~r~~"9.9.~,t~""",,,,,.~1,!.~QQ!.?,?a:,a~_~?,!,?~~,!?Q~_:Q?'__ ____"Ja~Qa!?_1 ?,:!.e_____"'___
Table Four (cant)
Comparative Load Control Program Costs 2009
2009 Costs
Cost Category Oct '08-Sept '09
A~~ini~tr~tiy.~.~~.PP?~_________.____ ,~??~:??"_,,,__
t.r9.~r~~~y.~I~~ti9.~.......__J~~~?:QQ___.___
__yi~I,~L,~9.~ipJ"q,~_~~,~i,~:_~~,~~~~~ ,,,,,g,ae1_!.~.~.a:.e~'"
~~,~icip~tion9.r.~~!t~ ..,. ...., ""---'''''--". $?,?~e,!,?~?,:,~~......
,_t.ro.~r~_m m~n~9.~~~~t . .... ....,"_,,______"" .... . $e?!!.eQ.:?......
__Rep?~in9.,__,,"_"'__ . "'_"________"".,,,..,SO,:O
",,,,,,,,,___!?t~!'!:9.flr.!','!_,9.9.~t~_ "",~~Q~e~Q,!,e,~Q:,?~"
Table Five
Schedule 72 Program Impacts by Participation Option
Site June July Avoided Aug, Avoided Sept
Participation Option Cnt Avoided kW kW kW Avoided kW
_,____"""""_".9p.tign,Lr._~,,?:a"""""""""s.Q ....,,_______J,"'eQ?,:.? . . ,,,,?J,S4,:.S ....______,,~Qa~:Q .....___,JLS§Q:9.,
,___QptlQ!IJJh_?':S__,44 __.._.,_ ........ ....,eS4,:,S ""_"______J,,QSs,:? '''_____,,___J!..1.Q?:9 __________".".,e4.,1.:?
__________"""".9p.tign,..,Lr._~..~:§....................?................_....._._,___.§§.s~O'.__"'_____"SS~,Q,__.......,S,a1ß_"""...._"?!.§.:,S__,,
"'_"__",Qp.tign,,i.Lr.,~..:!.,,"________Q__""""_ __"''''''"_",,,,_9:9.,,____..______,0.., ""_,,,___9.:9____,,,,""_ ,,___Q:Q__
",Qpti9.n,Illtn,~:a """..".",."t"..,,,_,,,..,,.,...,. 11.S.. .......,"""""..1,?,:.?......_....... . ,,___J.?:.S_..__,____,,__, 7 .0
"""__,,,Qp.~gnJIJ,!.n4.:!.____._..L._.___""___,,_,,___,,?o.§_,,__,,__"",., .. .. .?Q:,?___"..,....... Je:Q_____,.._...... 20,0
_________gp.tlC?n"i.i.Lr.,.t.,~J.n._~:§_.._........._.......s.,_,._...._"_.,,,Jt~iL_,,.,_______,,e,?:Q,,""',,Jga:.Q_,,__,,___e4.,:,S""
____"_.9p.tignIII,,r._t~J,n.A:!.___________A________,,___,,_,__,JQs:9._,_____1.91:,L___""" 19S:Q__"___".",,.,, 96,S
,Qpti9.nIY,n:?:ß 0 ... .9:9.",__"__._..._9:9__,_"_,,,,Q:9__ 0,0
Option IV w 2-8 1 34,0 33.0 33.0 33.0
Totals 123 3,782,S 4,162.S 4,12S,0 3,318.0
2009 Idaho Irrgation Load Control Quantiative Review Page 3
Tables Six through Nine transpose the data presented in Table Five into hourly dispatch schedules by each of the
four Schedule Forward dispatch days (Monday-Thursday). Each of the four subsequent tables indicates the avoided
kW by month, control day (Monday-Thursday) and hour.
Table Six
Schedule 72 2009 Avoided kW by Month, Monday Control Day & Hour
JUNE Monday Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW I 1,902.5 I 2,654.0 I 2,762.0 2,762.0 2,010.5 1902.5
JULY Mondav Avoided kW by Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 T 6:00-6:59 I 7:00-7:59
Avoided kW I 2,164.5 I 2,922.5 I 3,030.0 I 3,030.0 I 2,272.0 I 2,164.5
AUGUST Monday Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 2,083 I 2,852.5 I 2,958.5 I 2,958.5 I 2,189.0 1 2,083.0
SEPTEMBER Mondav Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 1 7:00-7:59
Avoided kW I 1,550.0 I 2,220.0 I 2,316.5 I 2,316.5 T 1,646.5 I 1,550.0
Table Seven
Schedule 72 2009 Avoided kW by Month, Tuesday Control Day & Hour
JUNE Tuesdav Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 1 6:00-6:59 I 7:00-7:59
Avoided kW I 954.5 I 1,061.5 I 1,190.0 I 1,190.0 I 1,083.0 I 954.5
JULY Tuesday Avoided kW by Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 1,066.5 I 1,174.0 I 1,302.0 I 1,302.0 I 1,194.5 1 1,066.5
AUGUST Tuesdav Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 1 7:00-7:59
Avoided kW I 1,102.0 I 1,222.5 I 1,347.5 I 1,347.5 T 1,227.0 I 1,102.0
SEPTEMBER Tuesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 941.5 1,043.0 1,159.5 1,159.5 1,058.0 941.5
2009 Idaho Irrgation Load Control Quantitatve Review Page 4
Table Eight
Schedule 72 2009 Avoided kW by Month, Wednesday Control Day & Hour
JUNE Wednesdav Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 1 7:00-7:59
Avoided kW I 1,936.5 I 2,688.0 I 2,796.0 I 2,796.0 T 2,044.5 I 1,936.5
JULY Wednesday Avoided kW by Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 2,197.5 I 2,955.5 I 3,063.0 I 3,063.0 I 2,305.0 I 2,197.5
AUGUST Wednesday Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 2,116.0 I 2,885.5 I 2,991.5 I 2,991.5 I 2,222.0 I 2,116.0
SEPTEMBER Wednesday Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 1,583.0 I 2,253.0 I 2,349.5 I 2,349.5 T 1,679.5 I 1,583.0
Table Nine
L
Schedule 72 2009 Avoided kW by Month, Thursday Control Day & Hour
JUNE Thursday Avoided kW by Hour
Hour I 2:00-2:59 1 3:00-3:59 I 4:00-4:59 i 5:00-5:59 T 6:00-6:59 I 7:00-7:59
Avoided kW I 954.5 I 1,061.5 I 1,190.0 I 1,190.0 I 1,083.0 I 954.5
JULY Thursday Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW I 1,066.5 I 1,174.0 I 1,302.0 I 1,302.0 I 1,194.5 I 1,066.5
AUGUST Thursdav Avoided kW bv Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 I 7:00-7:59
Avoided kW 1 1,102.0 1 1,222.51 1,347.5 1 1,347.51 1,227.0 I 1,102.0
SEPTEMBER Thursday Avoided kW by Hour
Hour I 2:00-2:59 I 3:00-3:59 I 4:00-4:59 I 5:00-5:59 I 6:00-6:59 T 7:00-7:59
Avoided kW I 941.5 I 1,043.0 I 1,159.5 I 1,159.5 I 1,058.0 I 941.5
2009 Idaho Irration Load Control Quantitative Review Page 5
Cost-effectiveness analyses
Cost-effectiveness is calculated for the following program components:
1. Schedule 72 (Scheduled Forward) only
2. Schedule 72A (Dispatch) only
3. Schedule 72 and Schedule 72A (combined)
Results on each of the four standard utilty industry tests-(1) Total Resource Cost (TRC); (2) Utilty; (3)
Ratepayer and (4) Participant will be provided for each of the three aforementioned program cases. The tests
for Schedule 72 (Scheduled Forward option) wil be based upon the cost and avoided MW values as defined
in Table Ten below2. The information below wil describe the methodology used in evaluating each of the
subsequent program components.
The Program cost-effectiveness analysis is based on the ratio of the present value of the Program's benefits
to costs and the net benefits (benefits minus costs), discounted at the appropriate rate for the various
benefiUcost tests3. The benefits (avoided costs) are based on the calculations as defined by the Company's
IRP organization and presented to the Idaho Public Utilties Commission, and the Idaho Irrigation Pumpers'
Association in a report titled Proposed Valuation Methodology for the Idaho Irrgation Load Control Program.
It should be noted that the avoided costs used in all cost-effectiveness analyses calculations presented in
this report considered the overall program size (Scheduled Forward + Dispatch program options) rather than
individual program characteristics. From an analytic perspective it is clear that the Dispatch initiative is
valued higher than a Scheduled Forward option. That said the extraordinarily smaller size of the Schedule
Forward initiative compared to the Dispatch option simply did not warrant a separate avoided cost analysis.
Table Ten
2009 Benefit / Cost Categories & Values-Schedule 72
Cost Categories
Administrative support
Program evaluation
Field I Equip I Db admin. expenses
Participation credits
Program management
Cost Values
$4.05
$67.12
$53,789.10
$43,912.27
$1,084.17
$9885671
Benefi Category
$/kW-yr avoided
Benefit Value
$73.09/kW
Total
Note: with the exception of partcipation credits costs have been allocted based on the percnt of load the
Schedule Forward option comprises of the total
Costs used in these calculations include administrative costs, contractor costs (field technician and database
design / administration), partcipant credits, and associated equipment costs. The participation credits are not
2 To the extent possible, certin cot cateories have been allocated by (1) the respeive Schedule initiative and (2) percnt of partcipating load.
3 Note that no discounting of costs or benefts was required in this analysis since all cots and benefits occurrd in proram year 2009.
2009 Idaho Irrgation Load Control Quantiative Review Page 6
included in the Total Resource Cost (TRC) test because they are a transfer payment from the utilty to the
participants.
The cost-effectiveness of the Program was calculated by Cadmus using a simplified spreadsheet analysis.
This analysis multiplies average demand reductions for the June, July and August period (as is consistent
with previous program year calculations) as a result of customers participating in the Program by the
estimated value of avoided demand noted above. As noted, the avoided demand value of is $73.09/kW-yr is
increased by 10.39% to account for the effect of T&D line losses, resulting in a value of $81.56/kW-yr used in
the cost-effectiveness calculations.
Based on previous research that showed energy use is 'shifted' rather than 'avoided', lost revenues are not
included as a cost and energy savings are not applicable as indicated above.
As shown in Table Eleven, the Scheduled Forward component of the program passes the TRC Test The
Scheduled Forward program also passes the Utilty and Ratepayer Test Since the participant incurs no costs
the benefiUcost ratio would be infinite for the Participant Test Accordingly, for the Participant Test the value
is indicated as 'N/A' in Table Eleven.
Table Eleven
2009 Cost-effectiveness Analyses-Schedule 72
Test Benefits Costs Net Benefits BenefiUCost Ratio
...""""..""..."""T~~".......".~.tS9..!t?e.:.?L_____J"§4,~~:A4.__._ "",,195,244.77 2.73
""""""".....".~tility """"""".~.1S9.!1?e:.?L_""_,,~eS,85alL_____:gJÆ.?:S9..,,,,_._.,,"_,,_"""" "J.:.S?___"_._.,,
..~~!=p.~~=~...~1.S9..!J?e.:.?1"__.._,,.,,_..Je.eßsell_____._""_~?.t!~.KS9._"".____._"""""._"J:§~____,,
"~~~i~i.p~~!.~4~!e.1.?.:?."""""""""""""""""""""""JO.o.,,H~!.e11_?!._._"___,,.___t-t.~__
Measurement & Verification (M&V) processes
The control equipment provides log files that can authoritatively determine issues of grower fraud and/or
tampering with the control equipment Throughout the 2009 season there remained a residual amount of
confusion among growers relative to equipment I program operations. Accrdingly, the Irrigation
Management Team decided that it would be important to provide additional M&V field technician site visits.
This was done to meet customer services as well as M&Vobjectives. In the end there were no sites reported
to be out of compliance relative to grower fraud. There was, throughout each of the site visits, significant
attention to training and easing grower fears I concerns regarding the remote control equipment
2009 Idaho Irrgation Load Control Quantiative Review Page?
2009 Schedule 72A (Dispatch) Results
Table Twelve
Schedule 10 Eligible & Full-Year Participating Sites & Customers
2008 Actual Participants
2009 Actual Participants
Eligible 2009 Counts
Customers NOT eligible to participate 2009
Participant Sites
1,491
1,927
4,723
N/A
Participant Customers
530
826
2,032
o
Customer Opt-Outs
Schedule 72A permits growers to 'opt-out' of five Dispatch Events throughout the Irrigation Season. Each of
these opt-out events incurred a cost resulting in a reduction to the customer's Load Control Service Credit
The cost to opt-out is the day-ahead ($/MWh) RMP would otherwise have to pay for power during that
dispatch period. A summary of opt-outs, liquidated damages and kW not avoided by each of the Dispatch
Events is presented in Table Twelve.
Table Thirteen
Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch Event
Dispatch Count of Liquidated kWNOT $/MWh
Count Date Weekday Opt-outs Damages avoided (day ahead)
1 30-Jun Tuesday 64 $1,410.86 9,533 $37.00
2 17-Jul Friday 117 $2,127.22 12,891 $41.5
3 23-Jul Thursday 85 $2,21375 11,776 $47.00
4 3-Aug Monday 42 $1,044.16 6,870 $38.00
5 5-Aug Wednesday 40 $1,166.96 7,294 $40.00
6 13-Aug Thursday 36 $648.82 4,159 $39.00
$8,611.77 52,521
Dispatch Events
Nominal loads avoided by the Dispatch Events are captured in Table Fourteen. Table Fifteen captures net
kW avoided for each Dispatch Event as opt-outs are netted from Table Fourteen calculations.
2009 Idaho Irrgation Load Control Quantitative Review Page 8
Table Fourteen
Dispatch Program Only Nominal Load (kW) Impacts x Dispatch Event
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 30-Jun Tuesday 231,042.4 231,042.4 231,042.4 231,042.4 0.0 0.0
2 17-Jul Friday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
3 23-Jul Thursday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
4 3-Aug Monday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
5 5-Aug Wednesday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
6 13-Aug Thursday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr.245,532.0 245,532.0 245,532.0 245,532.0 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr.244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
Table Fifteen
Dispatch Program Only Net Load (kW) Impacts x Dispatch Event
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 30-Jun Tuesday 221,509.9 221,509.9 221,509.9 221,509.9 0.0 0.0
2 17-Jul Friday 241,301.9 241,301.9 241,301.9 241,301.9 0.0 0.0
3 23-Jul Thursday 242,417.4 242,417.242,417.242,417.4 0.0 0.0
4 3-Aug Monday 237,718.237,718.4 237,718.4 237,718.4 0.0 0.0
5 5-Aug Wednesday 237,294.4 237,294.237,294.4 237,294.4 0.0 0.0
6 13-Aug Thursday 240,428.9 240.28.9 240,428.9 240,428.9 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr.236,778.5 236,778.5 236,778.5 236,778.5 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr.239,0737 239,0737 239,0737 239,073.7 0.0 0.0
Cost.efeciveness analyses
Cost-effectiveness calculations were prepared for each of the four standard utilty industry tests in the
manner consistent with that described above for the Schedule 72 portion of this program. Benefis and costs
for Schedule 72A (Dispatch option) upon which calculations are prepared are presented in Table Sixteen
below4.
Again, the cost-effectiveness of the Program was calculated by Cadmus using a simplified spreadsheet
analysis. This analysis multiplies average demand reductions for the June, July and August period (as is
consistent with previous program year calculations) as a result of customers participating in the Program by
the estimated value of avoided demand. In the case of Schedule 72A, the value of avoided demand is based
on the volume of avoided kW times dispatch hours and the benefit calculations provided by PacifiCorp. The
avoided cost benefits were presented to the Idaho Public Utilities Commission and the Idaho Irrigation
Pumpers' Association in a report titled Proposed Valuation Methodology for the Idaho Irrigation Load Control
4 Again, to the extent possible, costs have been allocted by the respectve Schedule initiative
2009 Idaho Irrgation Load Control Quantitative Review Page 9
Program. The 2009 value was determined to be $7309/kW-yr. Values are increased by 10.39% to account
for the effect of T&D line losses setting the value used in the calculations at $81 .S6/kW-yr.
Table Sixteen
2009 Benefit / Cost Categories & Values-Schedule 72A
Cost Categories
Administrative support
Program evaluation
Field I Equip I Db admin. expenses
Participation credits
Program management
Cost Values Benefi Category
$249.22 $/kW-yr avoided
$4,127.88
$3,308,029.58
$7,202,670.57
$66,676.58
$10581 75383
Benefi Value
$73.09/kW
Total
As shown in Table Seventeen, Schedule 72A passes the TRC, Utility and Ratepayer Tests. The Program also
passes the Participant Test. However, since the participant incurs no costs the benefit/cost ratio would be infinite.
Accordingly for the Participant Test the value is indicated as 'N/A' in the Benefit/Cost Ratio column.
Table Seventeen
2009 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
.. ...",,,,,!.~~.___,,S?9.!g?at!Q?':.S8 ",__",..i~!.~?e!gS3.26SJ.M4Z!.e?.1:~?.__.___.__ _______s.:e~__.________'"
.._~~!I!~~..s?9.,g?aJ_()X:S~J~Q,s~J_t!S~ß~_'" .....$eA~c9.SES....."'_____J:se_ .
R~~~P~t~~__S?'Q!Q?,e.t!Q?':.S§ .1~Q!.Sa~2S.~.:.~~___.SeA4.4.!.eS.ES ... 1 .89
"'_______~.~.~.i~ip~~~_"'........E.?Q?.i!Q.:.SL______._.__.JQ~9.Q___"'_g?9.?Æ9:S?.N/A___________"'...
2009 Idaho Irrgation Load Control Quantitative Review Page 10
2009 Schedule 72 & Schedule 72A Results
This section of the report provides quantitative summaries of the two combined initiatives-Schedule 72 (Scheduled
Forward) and Schedule 72A (Dispatch).
Avoided demand
Program impacts by participation option for both Schedule 72 and 72A are presented in Table Eighteen.
Table Eighteen
Program Impacts by Participation Option
June July Avoided Aug Avoided Sept Avoided
Option Counts Avoided kW kW kW kW
Option I m w 2-8 60 1,902.5 2,164.5 2,083 1,550
Option It th 2-8 44 954.5 1066.5 1102 941.5
Option II m w 3-6 7 656 663 661.5 575.5
Option II m w 4-7 0 0 0 0 0
Option II t th 3-6 1 11.5 12.5 12.5 7
Option II t th 4-7 1 20.5 20.5 19 20
Option III m t w th 3-6 5 95.5 95 108 94.5
Option III m t w th 4-7 4 108 107.5 106 96.5
Option IV m 2-8 0 0 0 0 0
Option IV w 2-8 1 34 33 33 33
Schedule Forward totals 123 3,782.5 4,162.5 4,125.0 3,318.0
Dispatch Option totals 1,927 231,042.4 254,192.9 244,587.9 0
Totals:2,050 234,824.9 258,355.4 248,712.9 3,318.0
The avoided demand by dispatch hour associated with each of the Dispatch Events is presented in Table
Nineteen. The values in this table are additive. That is, they represent the combination of Scheduled Forward
loads plus Dispatch loads. Table Twenty presents these same data with the exception that the opt-out loads
are taken into the calculations. Two important facts need to be taken into consideration in evaluating these
data. First, a zero (0) appears in two cells. This is due to the fact that the Scheduled Forward initiative
operates Monday thru Thursday inclusive. When the Dispatch initiative was exercised on Friday the only
avoided demand is that associated with Dispatch loads and none occurred after 6 pm on Friday. Second, the
table calculates the average (mean) as well as a median for each of the hourly loads per 'Dispatch Event'.
2009 Idaho Irrgation Load COntrl Quantitative Review Page 11
Table Nineteen
2009 Dispatch Events & Associated Avoided kW (Schedule 72 & Schedule 72A)
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 30-Jun Tuesday 231,996.9 232,103.9 232,232.4 232,232.4 1,083.0 975.0
2 17-Jul Friday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
3 23-Jul Thursday 255,259.4 255,366.9 255,494.9 255,494.9 1,194.5 1,066.5
4 3-Aug Monday 246,670.9 247,440.4 247,546.247,546.4 2,189.0 2,083.0
5 5-Aug Wednesday 246,703.9 247,4734 247,579.4 247,579.4 2,222.0 2,116.0
6 13-Aug Thursday 245,689.9 245,810.4 245,935.4 245,935.4 1,227.0 1,102.0
Mean 'Dispatch Event' Avoided kW x hr.246,752.3 247,064.7 247,163.6 247,163.6 1,319.3 1,223.8
Median 'Dispatch Event' Avoided kW x hr.246,687.247,456.9 247,562.9 247,562.9 1,210.8 1,084.
Table Twenty
2009 Dispatch Events & Associated Net Avoided kW (Schedule 72 & Schedule 72A)
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 30-Jun Tuesday 222,464.222,571.4 222,699.9 222,699.9 1,083.0 975.0
2 17-Jul Friday 241,301.9 241,301.9 241,301.9 241,301.9 0.0 0.0
3 23-Jul Thursday 243,483.9 243,591.4 243,719.4 243,719.4 1,194.5 1,066.5
4 3-Aug Monday 239,801.240,570.9 240,676.9 240,676.9 2,189.0 2,083.0
5 5-Aug Wednesday 239,410.4 240,179.9 240,285.9 240,285.9 2,222.0 2,116.0
6 13-Aug Thursday 241,530.9 241,651.241,776.4 241,776.4 1,227.0 1,102.0
Mean 'Dispatch Event' Avoided kW x hr.237,998.8 238,311.2 238,410.1 238,410.1 1,319.3 1,223.8
Median 'Dispatch Event' Avoided kW x hr.240,551.7 240,936.4 240,989.4 240,989.4 1,210.8 1,084.3
Season-long hourly load impacts are presented in Table Nineteen. The tan color-coding represents the hour and day
of dispatch events. The green color-coding represents Schedule Forward dispatches.
Table Twenty-One
Hourly Load impacts Entire 2009 Program Season
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
1-Jun
2009 Idaho Irrgation Load Control Quantitatie Review Page 12
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
Table Twenty-One
Hourly Load impacts Entire 2009 Program Season
8-Jun 10-Jun
Page 132009 Idaho Irrgation Load Control Quantitative Review
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
Table Twenty-One (cont.
Hourly Load impacts Entire 2009 Program Season
6-Jul 8-Jul 10-Jul
2009 Idaho Irrgation Load Control Quantitative Review Page 14
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
hour
2:00-2:59
3:00-3:59
4:00-4:59
5:00-5:59
6:00-6:59
7:00-7:59
Table Twenty-One (cont.)
Hourly Load impacts Entire 2009 Program Season
2009 Idaho Irrgation Load Control Quantitative Review Page 15
Load profile data impact analysis
Throughout the control period, Company SCADA data were collected and used in preparing impact analyses.
Attachment One includes 60s SCADA data for each of the following five transmission substations on each of the
dispatch event days: (1) Amps; (2) Big Grassey; (3) Rigby; (4) Bonnevile and (5) Jefferson. The impact of load
dispatches is dramatic and unequivocaL. When interpreting these plots keep in mind that June was 348% of normal
rainfall and only 55% of normal temperature. Hence, the magnitude of June loads is significantly less than previous
seasons. Further analysis suggests that the maturing of field crops and the 2nd cutting for alfalfa hay have a
predictable impact on reducing loads post August 1st.
Cost-effectiveness analyses
Cost-effectiveness calculations were prepared for each of the four standard utility industry tests in a manner
consistent with the methodologies described earlier. In this evaluation, however, full program costs for both
Schedule 72 and Schedule 72A together with benefits from both program components are used as the basis for the
evaluations. Benefits and costs for Schedule 72 and 72A upon which calculations are prepared are presented in
Table Twenty-two below5.
Table Twenty-two
2009 Benefit I Cost Categories & Values-Schedules 72 & 72A
Cost Categories
Administrative support
Program evaluation
Field I Equip I Db admin. expenses
Participation credits
Program management
Cost Values Benefit Category
$253.27 $/kW-yr avoided
$4,195.00
$3,361,818.68
$7,246,582.84
$67,760.75
$1068061054
Benefit Value
$73.09/kW
Total
All-in $/kW program costs6 $41.4 Total kW 258,355.4"
"Total max load for July
As shown in Table Twenty-three, the combined initiatives (Schedule 72 + Schedule 72A) pass the TRC, Utilty and
Ratepayer Tests. The Program also passes the Participant Test. However, since the participant incurs no costs the
benefit/cost ratio would be infinite. Accordingly and for the Participant Test the value is indicated as 'N/A' in the
Benefit/Cost Ratio column.
5 All program costs (both Scheduled Forward and Dispatch proram components) have been included in this table.
6 This is a rudimentary calculation simply penormed by dividing all proram costs by the monthly max (July) avoided demand.
2009 Idaho Irrgation Load Contrl Quantitative Review Page 16
Table Twenty-three
2009 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
",,,,,...,,,,TR9.,,,, ......~?Q.!J.~a!.~S4:9L._.__._S~!~34!Q??:ZQ..JJe,T1S,~Se.,.~?,,"" ..........S.:?L""",,"',,""""'.......
........",,,,,....,,.......~!.i'.i.!~,, ......~?Q.!JAe.!~?4.:9L__._._~lQ!e.SQ!e.1Q:Si..._____~,~_e?!.??~.:.s?.""", . """""""J":?e,,
""""",,,,,R~!~p'.~~~~,,,,,,,,,,,,~?'Q.!.1.4e.!~S4.:.9,,,,,,,,,,,,,,.~1.9!e.SQ.!e.1Q:-~L__~e!~eS.!.?T~.:?_L__.__._......."""J.&e_._",.",.
~a~i~ip~n_!g?4e!S??&4 ...............~Q:Q9_ """",,,..g.?4.eJ~~2~S'!___,,__._,,__ .",_..__N/A _.__._"""
Conclusions
Grower perception considerations
.:. The 2009 Dispatch initiative was positively received by the growers with no indication from growers that
either row or field crops were adversely affected by quality or yield impacts
.:. Key to program success is maintaining a local presence of agri-irngation I information systems specialists
and irrigation equipment I ag-electrician specialists.
.:. Throughout the 2009 season additional growers began to actively use the remote control equipment for
regular irngation turns. That said, there has been and remains a variety of interesting technical issues and
operational considerations that require additional attention to ensure system robustness.
Meteorological considerations?
.:. From a meteorological perspective June was an anomaly. Rainfall was 348% of normal and temperatures
only 55% of normaL.
.:. The two above mentioned factors translated into virtually no (zero) pump load during June.
.:. July temperatures were 114% of normal (as measured by the ¿COD and rainfall was 39% of normal
.:. August temperatures were 97% of normal (again, as measured by ¿COD) and rainfall was 53% of normal
.:. Over the three summer months rainfall was 149% of normal and temperature 95% of normal
Peak considerations
.:. In the arid intermountain west it is high night-time lows that drive system peak. 2009 was unique in that
there were only four instances where the night-time low stayed ~ 700F. Moreover, only two of those days
where the night-time low stayed ~ 70°F fell on a weekday.
.:. In 2007 the all-time system peak was reached. In 2009 that peak was never close to being breeched. This
was likely due to a slower economy and more normal-like temperatures. Nevertheless, dispatch events
were executed coincident with each of the respective three summer months, day and hour peaks.
7 All data is base on Salt Lake City. This is relevant as RMP east-side grid contrl area is driven by Wasatch Front meteorological considerations.
Furter note that 'normal' was calculated over a 40-year time horizon.
2009 Idaho Irrgation Load Control Quantitative Review Page 17
Dispatch considerations
.:. As is evident in Attachment One loads are either precipitously removed from (upon dispatch initiation) or
added to (upon dispatch conclusion) the RMP grid.
.:. Altogether, the irrigation load control initiative accounts for -40% of the Goshen Transmission Substation
and nearly 80% of four of the five transmission substations monitored.
.:. Idaho Engineering Area Planning is concerned that too much load is either removed from or added to the
system in too narrow of a time-frame (causing voltage imbalances).
.:. With the exception of the Rigby Transmission Substation there is virtually no load diversity on the four
transmission substations; (1) Amps; (2) Big Grassey; (3) Jefferson and (4) Bonnevile.
.:. Upon initiation of a dispatch event voltage spikes above tolerances of existing substation and/or circuit
protective equipment and systems.
.:. Upon the conclusion of the dispatch event when loads are once again returned to their 'normal' position
voltage drops below tolerances of existing substation and/or circuit protective equipment and systems.
.:. Currently there is simply insuffcient time delay in either substation and/or system circuitr to accmmodate
the dramatic voltage changes.
Recommendations
Changes to dispatch protocols
.:. Plenary discussions with RMP Area Planning (Idaho) has determined that a more intellgent stepping into
and out-of dispatch events will correct the voltage spikes / sags currently occurring.
.:. Changes to the dispatch protocol may be an effective strategy to delay additional capital investment in
infrastructure assets.
.:. Changing the dispatch protocol wil require analysis of the RMP engineering database to determine geo-
spatial load locations as well as coordination with growers
.:. A changed dispatch protocol wil require the available dispatch windows to be lengthened
.:. The aforementioned changes have been discussed with Idaho growers and with members of the Idaho
Irrigators Pumpers' Association (IIPA).
.:. The IIPA is supportive of the requisite changes.
.:. Tariff modification were proposed and approved in Advice 09-05 extending dispatch hours from 11 :00 AM
to 7:00 PM MST.
2009 Idaho Irrgation Loa Control Quantitative Review Page 18
Attachment One
Schedule & Duration of '09 Dispatch Events
IDAHO
30 June""""""""" 4 hrs
17 July"."""."""". 4 hrs
23 July.""""""""" 4 hrs
3 August """""".".4 hrs
5 August """."""".4 hrs
13 August """"""..4 hrs
Total hours""."""" 24
Note: all dispatch events were executed between 2:00p-6:00p
Further Note: dispatch events were executed coincident with individual month, day and hour as well as seasonal
peak periods
Load Plot Contents
Rocky Mountain Power Transmission Substations """"""""."""."""".".""""""""".""""""""""...""""""""""". 20
Big Grassey Transmission Substation (30 June) """""""""""""""""".""."".""...""""..."........""."",,.,,",,..,,""".21
Big Grassey Transmission Substation (17 July) "....""""."""""""".."..""""""""""""""""".".,,"",,....,,.,,""""",,. 21
Big Grassey Transmission Substation (23 July) """..."..."...""""""""""""""""""""".""""""""""""""".,,",,.,,".22
Big Grassey Transmission Substation (3 August) .".."....."""""""""""...""""".""",,.,,"""",,.,,"""""",,....,,""""" 22
Big Grassey Transmission Substation (5 August) ."""""."""""""""""".""."""""""""""""""""""""..""..""""" 23
Big Grassey Transmission Substation (13 August) """"""""."""""""""""""""".""".,,",,...,,""""""""""""",,.... 23
Amps-Monteview Area Transmission Substation (30 June) """"""..""""."""""""""""""""""",,..,,""""""""",,.. 24
Amps-Monteview Area Transmission Substation (17 July)"."."""""""""".."""""""""""..""""""""""""""."""" 24
Amps-Monteview Area Transmission Substation (23 July)"".""""""""."""""""""""""""".."""""""""""""""". 25
Amps-Monteview Area Transmission Substation (3 August) ......................................................................................25
Amps-Monteview Area Transmission Substation (13 August) """""""""""".""....""""""""...".,,"""""""""",,..... 26
Rigby Transmission Substation (30 June) ."""""""""".""""".."""""""""""".."""""."".,,,,.......,,.,,",,.,,""""."".. 27
Rigby Transmission Substation (17 July)....................................................................................................................27
Rigby Transmission Substation (23 July)"...."....""""""."""""""""",,.,,.,,"""""""""""""""""""""""".""""""" 28
Rigby Transmission Substation (3 August) ."""""""""""."".""".."",,.,,""""""""""""",,..,,""""""""""",,.""""" 28
Rigby Transmission Substation (5 August) ."""""""".".""""..""""""".""""".,,""""",,.,,",,..,,""",,..,,""""""""".29
Rigby Transmission Substation (13 August) """""""""."""""""""""""""""""""""""""""""""""""""."""."".. 29
Bonnevile Transmission Substation (30 June) """""""""""""""""""".""""""""""""""""""""""""""""""""" 30
Bonnevile Transmission Substation (17 July) """"""...""""""""""""""""""""""""""""."."""""""."..""""""" 30
Bonneville Transmission Substation (23 July) """.."..""""".""""."""..".""""""""""..,,"""""""""",,.,,,,.,,",,.""" 31
Bonnevile Transmission Substation (3 August) ."..""""""""."""."...."".,,""""""",,""""""""""",,..".."",,.,,"""" 31
Bonnevile Transmission Substation (5 August) ."""""."."""""""".."""."""""""."".""""""""""""""..""""""".32
Bonnevile Transmission Substation (13 August) """"""..."""""""""""".."""""""""".".."".""""""".,,,,..,,""",,. 32
Jefferson Transmission Substation (17 July) .""""""""."""."...""""""""""",,"""""""""",,.."""""""",,.,,""....".33
Jefferson Transmission Substation (23 July) ."""""""""""""""""""""."""""""""""""""""""""""..""""."""".34
Jefferson Transmission Substation (3 August) """.""""."""""""""""""."""""""..."".""""""""."."''''''''''''"""" 34
Jefferson Transmission Substation (5 August) "."""""".""""""".".""""""""""""""""""""""""..""'"''''''''''''"" 35
Jefferson Transmission Substation (13 August) ...""""""""".""""""...".,,"""""""""""""""""""",,..,,.,,""""""" 35
2009 Idaho Irrgation Load Control Quantitative Review Page 19
Rocky Mountain Power Northern Tier Transmission Substations
2009 Idaho Irrgation Load Control Quantitative Review Page 20
Big Grassey Transmission Substation (30 June)
big grassey 30 june 09
35
15
30
25
20
~
10
ON~~~ON.Ø ~ONvIDroONv m ro ONvm ~ 0 NvW roONvWro 0 NvWroONvIDWOMOMOv~v~vN~N~NOMO M 0 v_v_v N ~ N~ NOMOMOv ~v_vN~N~Nöö~~NN ~ ~~~~~~~~~~mm öö ~~NN M M ~~ ~~~~~m~ mmöö~~NNM_ _____ _ _ __ _____ __ __NNNNNNN
lime (24 his)
60s load dala I
Big Grassey Transmission Substation (17 July)
big grassey 17 july 09
55
15
50
45
40
35
30
~
25
20
10
ONvID WON VWWO Nv mwo NvIDW ONvIDW 0 N vm W ONv mwo NvIDWONvWWOMOM 0 v _ v_vN~N~NO MOMOv_v_v N ~ N~NOMO MOv _ v_vN~N~Nöö~~ N N M M~.~ ~ ~ ~~~ ~mmöö~~NNM M ~.~~ ~~~ ~~ mmÖÖ~~NNM____ ____ ____ __ _ ____ N N NNN NN
lime (24 his)
60s load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 21
Big Grassey Transmission Substation (23 July)
big grassey 23 july 09
55
10
50
45
40
35
30
s::;
25
20
15
g ~ ~ ~ ~ e ~ ~ ~ ~ ~ ~ ~ ~ reg ~ ~ ~ ~ e ~ ~ ~~ ~ ~ ~ ~ re g ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ reö ö ~~ N N M M ~ ~ ~ ~ ~ ø ~ ~ ~ m m ~ g ~ ~ ~~ ~ ti ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~
lime (24 hrs)
60s load dolo I
Big Grassey Transmission Substation (3 August)
big grassey 3 august09
10
30
25
20
~ 15
ON.~ ~ 0 N .~roo N. W roo NvWroONvWroO NVWroO N. W mONv W ro ONv wro~~ ~~ ~~;, ~;.~~ ~ ~ ~ ~~ ~~~~~;,~ :.~~~ ~~~~ ~ 9 ~ 9~:.~:. ~ ~~~~~OO~~ NN M Mv.~~ W w ~ro rommoo~ ~NNM M ..~m m ~ ~ wromm 0 0 ~~NNM~~~ ~ ~~~~~~~~ ~ ~~ ~~~~ N N NNNNN
time (24 hrs)
60s load dolo I
2009 Idaho Irrgation Loa Control Quantitative Review Page 22
Big Grassey Transmission Substation (5 August)
big grassey 5 august 09
30
10
25
20
~ 15
ON~wmON~W mON~wmON.W m 0 Nvwm 0 N.W mONvwmo NvIDmONv wm~~~~~~:.~;.~~~~~~~~~ ~ ~ ~ :.~:.~ ~ ~ ~~ ~~~~~~~ ;.~:.~~~~~~00 ~~NNM Mv v~~IDID~mm~ ~ 0 O~~NN M M vv ~WID~~m m ~æOO~~NNM~ ~~~~~ ~ ~ ~~ ~~~~~~~ ~~NNNNNNN
time (24 hrs)
60s load data i
Big Grassey Transmission Substation (13 August)
big grassey 13 august 09
25
15
20
~
10
8 ~~~ ~ ~ ~ ~~~~ ~ ~ ~ ~8 ~~~~~~ ~~~~~~~reg ~ ~ ~ ~~~: ~ ~ ~~~ ~~öö~~ N NM M~~~ ~ ~ ~ ~~ ~ ~ ~~~~~ ~~~ti~~~~~ ~~~~~~ ~~~~~~~
time (24 hrs)
I-60s load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 23
Amps-Monteview Area Transmission Substation (30 June)
amps 30 june 09
16
12
14
10
~
ON ~~ro ONvØroO Nv m roo Nv m ro ON. mrooNvwroO N v m roON. m ro ONv wroOM OM Ov~.~vN ~ N~ NO MOM 0 v~v ~vN~N~NO MOM OV~V ~ v N~N~NÖÖ ~~NN~M. ~~ ~ë~~~ ~~ ~ g g~~ ~~~~~~~~~~~~~~~ ~~~~~~~
time (24 hrs)
60s load data I
Amps-Monteview Area Transmission Substation (17 July)
amps 17 july 09
55
15
50
45
40
35
30
25
20
10
g ~ ~ ~ 8 e ~ ~ ~ ~ ~ ~ ~ ~ reg ~ ~ ~ ~ e ~ ~ ~~ ~ ~ ~m re g ~ ~ ~ ~ e ~ ~ ~ ~ ~~ ~ ~ reö ö ~ ~ N N M M ~ ~ ~ ~ ID ~ ~ ~ ~ ~ m è g ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~
time (24 hrs)
60s load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 24
Amps-Monteview Area Transmission Substation (23 July)
amps 23 july 09
50
10
45
40
35
30
~ 25
20
15
g~ ~~ ~~ ~~~~~ ~ ~ ~ reg~~~~e~~ ~~~~~~reg~~ ~ ~~~: ~~ ~~~~reö ö ~ ~ N N M M ~ ~ ~ ~ m ID ~ ro ro ~ ~ ~ è ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~. ~ ~
time (24 hrs)
I-60s load data I
Amps-Monteview Area Transmission Substation (3 August)
amps 3 august 09
18
14
16
12
10
~
ON~ID ~ 0 N ~Ð~O N ~ IDmo NvIDm ONvIDm 0 N vwm 0 N v ID WON. ID WON. IDW~~~~ ~ ~:. ~:.~~~~~ ~~ ~~~~~:.~:.~ ~ ~ ~~~~ ~ 9 ~ 9~:.~:. ~ ~~~ ~~OO~~ N N M Mvv~~ ID ID~W wææOO~~NN M M vv~m ID~~ ww ææ 0 0 ~~NNM~~~~~~ ~ ~ ~~~~ ~ ~ ~ ~~~~ N N NNNNN
time (24 hrs)
I-60s load data I
2009 Idaho Irrgauon Load Control Quantitative Review Page 25
Amps-Monteview Area Transmission Substation (5 August)
amps 5 august 09
14
12
10
~
ON ~ W ~ ON e ~ ~ 0 N ~ ~ ~ 0 N ~ ~ ~ 0 N ~ m ro 0 N e m ~ 0 N ~ m ~ 0 N v m ~ 0 N e m ~~~ ~~~~:.~:.~~ ~ ~ ~ ~~ ~~ ~~~:.~ :.~~~~~ ~9 ~9~9~:.~ :.~~~~~~00 ~~ NNM Mvv~ ~ m m ~~ ~ ~ ~o o~~ NNMMvv~mm ~~ w~~m OO~~NNM~~~~ ~~~~~~~~~ ~~~~~~ NNNNNNN
time (24 hrs)
I-60s load data I
Amps-Monteview Area Transmission Substation (13 August)
amps 13 august 09
20
18
16
14
12
~ 10
ONvm ~ 0 N vm~ONvm~o Nvm ~ 0 NvIDW 0 N vm ~ 0 N v m wo NvmøONv mw9 ~9~ 9 ~:. ~:.~~~~~~9 ~9~9~:.~:.~ ~ ~ ~~ ~9 ~ 9 ~ 9~ :.~:. ~ ~~~ ~~OO~~ N N M Mvv~~m m~w ømmOO~~NN M M VV ~ m m ~ ~ ww m moo ~~N NM~~~~~~ ~ ~ ~~~~ ~~~ ~~ ~~N N NNN NN
time (24 hrs)
I-60S load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 26
Rigby Transmission Substation (30 June)
rigby 30 june 09
140
130
120
110
100
90
80
~ 70
60
50
40
30
20
10
ON. W ~ ON ~ W~ 0 N v ID ~ 0 N v ID ~ 0 N v W ~ 0 N vID ro 0 N v ID ~ 0 N v W ro ON VW ro~ ~~ ~ ~~;. ~:.~ ~ ~ ~ ~ ~ ~ ~9 ~ a~:. ~:. ~ ~ ~ ~~ ~ 9 ~ 9 ~ 9 ~:. ~:. ~ ~~ ~~ ~o o~ ~ N N M M vv ~ ~ W ID ~ ro ro ~ m 00 ~ ~ N N MM.. ~ ID ID ~ ~ ro ro m moo ~~ NN M~~~~~~~ ~~~~~~~~~~~ ~NNNNNNN
time (24 hrs)
1-60. load data I
Rigby Transmission Substation (17 July)
riby 17 july 09
170
160
150
140
130
120
110
100
90~E 80
70
60
50
40
30
20
10
o Nv wro ON. WroONvWroO Nv wroo NvmrooNvwmo NVWro ONvwmONvID m9 ~ 9 ~ 9~:. ~:.~ ~ ~ ~ ~~ 9 ~ 9 ~ 9 ~:. ~:. ~ ~ ~ ~ ~ ~ 9 ~9 ~ 9 ~:. ~:. ~ ~ ~ ~~ ~o o~ ~NNMM .v~~ Ww~mmm m 00 ~~NNMMvv~W m~~mmmmOO~~NNM~~ ~~~~~~~~ ~~~~~~~~~NNNNNNN
time (24 hrs)
60. load data I
Page 272009 Idaho Irrgation Load Control Quantitative Review
Rigby Transmission Substation (23 July)
Jiby 23 july 09
180
170
160
150
140
130
120
110
100
~90E
80
70
60
50
40
30
20
10
ON v ID WON v ID~ 0 N v ID WON v ID we Nv ID W 0 Nv ID m 0 N v ID WON v ID WON v ID Wo MO M 0 v ~ v ~v N~ N~ NOM 0 M OV _ v ~V N ~ N~ NOM 0 M 0 v ~ V~ v N ~ N ~ NÖ Ö ~ ~ N N M M ~~ ~ ~ ~ ~ ~ ~ ~ m m ~~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~~ ~~ ~ ~ ~ ~
time (24 his)
I-60s load data I
Rigby Transmission Substation (3 August)
ribgy 3 august 09
120
110
100
90
80
70
~ 60
50
40
30
20
10
o NvIDWONvIDW ONvIDW ONvIDWONVIDWO NvIDW 0 NvIDWON v WroON VID WOM 0 M 0 v ~ v ~V N ~ N~ NOM 0 M OV ~ v ~ v N ~ N~ NOM 0 M 0 v ~ v~ v N~ N~ NÖ Ö ~ ~ N N M M ~~ ~~ ID ID ~ ~ ~ m m ~~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~~~ ~~ ~
time (24 his)
60s load data I
Page 282009 Idaho Irrgation Load Control Quantitative Review
Rigby Transmission Substation (5 August)
riby 5 august 09
120
110
100
90
80
70
~ 60
50
40
30
20
10
g ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~re g ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~re g ~i ~ ~ ~ ~ ~ ~ ~ ~~ ~~ reci o~ ~ N N MM.. ~ ~ ~ ~~ ~ ~ ø m g g ~ ~ ~ ~ ~ t ~ ~~ ~ ~~ ~~ ~ ~ ~ ~ ~ ~ ~ ~~ ~
time (24 hrs)
60s load data I
Rigby Transmission Substation (13 August)
r1by 13 august 09
100
90
80
70
60
~ 50
40
30
20
10
o Nv m ro 0 N v m ro 0 N v m WON v m ~ 0 N v m ro 0 N v m WON v m ro 0 N v m WON vID roOMO MOv~v ~v N~N~NOMOM 0. ~V~V N~N~NOMOMOV~ V~ vN~N~NÖ Ö~ ~ N N MM.. ~ ~ w ~ ~ ~ ro m m gg ~ ~ ~ ~ t ti ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~
time (24 hrs)
I-60S load data I
Page 292009 Idaho Irrgation Load Control Quantitative Review
Bonnevile Transmission Substation (30 June)
bonneville 30 june 09
50
15
45
40
35
30
~ 25
20
10
g~~~~e~~~ ~~~~~reg~~ ~ ~ e~~~~~~ ~~ ~g~g~~s ~~~~~ ~~~reö ö ~ ~ N N MM. ~ ~ ~ ~ ~ ~ ~ ~ m m ö ö ~ ~ N N M M ~ . ~ Ð ~. ~ ~ ~ ~ m m ö ö ~ ~ N N M~ ~~~~~ ~ ~ ~~ ~~~~~~~ ~~NNNNNNN
time (24 hrs)
I-60S load data I
Bonnevile Transmission Substation (17 July)
bonneville 17 july 09
55
10
50
45
40
35
30
~
25
20
15
ON VW W 0 NvWWO N v m ~O N VW W ON v m~ ONvWWO N v m WON. m WON. mwOM OM 0 v ~ v~vN ~ N ~ NO MOMOv~ v ~.N~N~NO M 0 MOv~v ~ v N~N ~NCÖ ~~ NN MM ~~~ ~ W W ~W w m möö~ ~ NNMM..~m W ~~ wwmm ö ö ~~NNM~~~ ~ ~~~~~~~~ ~ ~~~~~~ N N NNNNN
time (24 hrs)
I-60s load data I
2009 Idaho Irrgation Load Control Quantiative Review Page 30
Bonnevile Transmission Substation (23 July)
bonneville 23 july 09
55
15
50
45
40
35
30
~
25
20
10
ON .~~ ONe~~O NVW ~ONv W ~ ON v m~ONvm ~O NV m~ONv m~ 0 Nvm~OM OMOv~v~vN ~ N~ NOMe M 0 v~ v ~vN~N~NOMOMOv~v~v N ~N~N00 ~~NN~~~~~ ~m m ~~Ðm m ~ g~ ~ ~~~~~~~~~~~~~~~ ~~~ ~~~~
time (24 hrs)
60s load data I
Bonnevile Transmission Substation (3 August)
bonneville 3 august 09
35
15
30
25
20
~
10
ONvWØ 0 N vIDWONvmwo NvID ro ONvWro 0 N VW roONv mroo NvIDWO Nv mw~~~~~ ~:. ~:.~~~~~~~ ~~~ ~~:.~:.~ ~ ~ ~~ ~~~~ ~~~ :.~:.~~~~~~OO~~N N MMvv~~IDID~ro ro~ ~ 0 O~~NN M M vv ~IDID~~roW ~moo_ ~NNM~~~~~~ ~ ~ ~~ ~~~~~~~ ~~NNNNNNN
time (24 hrs)
60s load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 31
Bonnevile Transmission Substation (5 August)
bonneville 5 august 09
30
10
25
20
~ 15
ON~ID~ON~ID ~o N.mWONv ID ~ ON ~ IDW 0 N.m WON.mWONvIDW 0 NvIDW~ ~ ~ ~ ~ ~;. ~;. ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~:. ~:. ~ ~ ~ ~~ ~ ~ ~ ~ ~ 9~:. ~:. ~ ~ ~ ~ ~ ~00 ~~NNMMv v~ ~IDID~WWm ~ ~ ~~ ~ ~~~~~~ ~~~~~~~ ~~~~N Ñ~~~
time (24 hrs)
I-60s load data I
Bonnevile Transmission Substation (13 August)
bonneville 13 august 09
20
12
18
18
14
~ 10
~~ ~~a~~;~~~ ~ ~ ~ ~~ ~~~a~~; ~~~~~~~a ~ ~ ~a~~; ~; ~~~~~00 ~~ N N M Mvv~ ~ ID ID ~w W ~ ~oo~ ~NNMMvv~ID ID ~ ~ wwmm 0 0 ~~NNM~~~~ ~~~ ~~~~~ ~ ~ ~ ~~~~ N N NNNNN
time (24 hrs)
60s load data I
2009 Idaho Irrgation Load Control Quantitative Review Page 32
Jefferson Transmission Substation (30 June)
jefferson 30 june 09
60
55
50
45
40
35
~ 30
25
20
15
10
ON ~W ~ 0 N vwm 0 N v W ~O NvW~ON v ØW 0 NvID~O N v mroo Nv ID WON. WWOM OM 0 v ~ v ~vN ~ N ~ NOMOMOv~ v ~vN~ N~NO M 0 MO.~v ~ v N~N ~N00 ~~ N NM M.~~ ~ ~ ID ~~ ~mæg~~ ~~~~~~~~~ ~ ~ ~~~~~~ ~ ~~~ ~~
time (24 hrs)
60s load data I
Jefferson Transmission Substation (17 July)
jeffrson 17 july 09
65
60
55
50
45
40
35
~
30
25
20
15
10
~~~~~~ ~;~ ~~~~~~a~~~ ~~~;~; ~~ ~~ ~s~~~~~ ~;~~~ ~N~~OO~~N N M Mv V~~IDID~wwm mo O~~NN M M vv ~ww~~ww mmoo_ ~NNM~~ ~~~~ ~ ~ ~~ ~~~~~~~ ~~NNN NNNN
time (24 hrs)
I-60s load data I
2009 Idaho Irrgation Load Control Quantitauve Review Page 33
Jefferson Transmission Substation (23 July)
jeffrson 23 july 09
65
60
55
50
45
40
35
~
30
25
20
15
10
o N~W ~ 0 N ~ID~ 0 N v ID ~O NvID~ONvID~ 0 N vID W 0 Nvm~O Nvm~O Nvm~~~~~ ~ ~;,~:. ~~ ~ ~~ ~~ ~~~~~:.~:.~ ~ ~ ~~ ~~~~~~~ :.~:.~~ ~~~~OO~~ N N M Mv v~~ m m~~ ~~ ~O O~~NN M M vv ~mm~~~ ~ mmoo~ ~NNM~~~~~~~~ ~~ ~~~~~~~ ~~NNN NNNN
time (24 hrs)
I-60S load data I
Jefferson Transmission Substation (3 August)
Jeffrson 3 august 09
45
40
35
30
25
~
20
15
10
ONvm ~ 0 N vm~o Nvm~ONv ID ~ ONvm~ 0 N vID ~ONvm~ 0 Nvm~o Nvm~OMOM 0 v ~ V~VN~N~NO MO M 0 V~V~V N ~ N~ NOMOMOv ~V~VN ~N~Nöö~~ NN ~ M~.~~IDID~ro~m m ÖÖ~~NNM M ~~ ~~~~~~ro mmöö~ ~NNM~ ~~~ ~~~~~~ ~~~~~~~~~NNN NNNN
time (24 hrs)
60s load data I
2009 Idaho Irrigation Load Control Quantitative Review Page 34
Jefferson Transmission Substation (5 August)
jeffrson 05 august 09
40
35
30
25
~ 20
15
10
ON ~ID~ ONVID~O N ~ ID ~O Nv ID ~ON v ID~ONvW~O N v ID ~ONv ID~ONv ID~OMOM 0 v ~v ~vN ~ N ~ NO MOMOv~ v~vN~ N~NO M 0 MOv~ v ~ vN~N~Noö~~ N N M M~.~~ ~ in~w wmm~~~~~~ ~ ti ~~~~~~~~~ ~~~~~ ~~~~
time (24 hrs)
I-60s load data I
Jefferson Transmission Substation (13 August)
jefferson 13 august 09
40
35
30
25
~ 20
15
10
g~~~~~~~~~~~~~reg~~ ~ ~ ~~ ~ ~~~~~mreg ~~~~~~~ ~~ ~~~mreöö ~~NNMM..~ ~ W w ~wwæmöö~ ~ NNMM..~W W ~ ~wromm ö ö ~~NNM~~~~~~~~~~~~ ~ ~ ~~~~~N NNNN NN
time (24 hrs)
60s load data I
2009 Idaho Irrgation Load Control Quantiative Review Page 35