20140707Hymas Exhibits 1-4.pdf

case No. pd8{b4Lm? il'l
ExhibitNo. 1
Witress:
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOI.INTAIN POWER
Exhibit Accompanying Direct Testimony of Kathryn C. Hymas
It:Jy 2014
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Rocky Mountain Power
Exhibit No. 1 Page 1 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
Exhibit No. 1.1
2010 Annual Report
Rocky Mountain Power
Exhibit No. 1 Page 2 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Rocky Mountain Power
Energy trfficiency
and Peak Reduction
Annual Report r Idaho
Rocky Mountain Power
Exhibit No. 1 Page 3 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Table of Contents
Introduction and Executive Summary ....................4
2010 PerforTnance and Activity ............6
Company Filings with the Idaho Public Utilities Commission............... ................... l0
Peak Reduction Program and Activity .................. I I
Energy Efficiency Programs and Activity............... ............... 14
Residential Energy Efficiency Programs and Activity ........... 15
Non-Residential Energy Efficiency Programs and Activity .....................23
Market Transformation - Northwest Energy Efficiency Alliance ............ 30
Summary of 2010 Results:..... .............31
Balancing Account Summary .............34
Cost Effectiveness:..... ....... 35
Appendices:................. ......37
Table
Table l:
Table 2:
Table 3:
Table 4:
Table 5:
Table 6:
Table 7:
Table 8:
Table 9:
Table l0:
Table I 1:
Table 12:
Table 13:
Table l4:
Table l5:
Table l6:
Table 17:
Table 18:
Table l9:
Table 20:
Table 2l:
Table22:
Table23:
Table24:
Rocky Mountain Power
Exhibit No. 1 Page 4 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
of Tables
Total Portfolio Performance.......... ..........4
Energy Efficiency and Peak Reduction Annual Results...... ........6
Program Evaluation Timeline... ...............9
Load Management Portfolio Performance................ ................. 1l
Inigation Load Control Program Performance................ ..........12
2010 Energy Efficiency Portfolio Performance ............... -........14
Home Energy Savings Program Performance................ ........... 15
Home Energy Savings Measure Performance................ ........... 16
See ya later, refrigerator@ Program Performance................ ..... 19
See ya later, refrigerator@ Results...... ................... 19
Low Income Weatherization Performance................ ..............21
Energy FinAnswer Program Performance................ ...............23
Energy FinAnswer by Measure Type......... ........... tJ
FinAnswer Express Program ...............25
FinAnswer Express by Measure Type......... ..........25
Agricultural Energy Services Program Performance ............... .................27
Agricultural Energy Savers by Measure Type.......... ................28
Revenues (Schedule l9l) by Customer Type.......... ................ 3l
Expenditures (Schedule 191) by Customer Type ......... ........... 31
Expenditures (Schedule 191) by Type of Program ...-........-.....32
Total expenditures by Type of Program ................32
Energy Efhciency Expenditures by Customer Type ................ 33
Energy Efficiency Results by Customer Type...... ................... Ji
Balancing Account Activity (Schedule l9l)........... ................ 34
Rocky Mountain Power
Exhibit No. 1 Page 5 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Introduction and Executive Summary
Rocky Mountain Power (the "Company") working in partnership with its retail customers and
with the approval of the Idaho Public Utilities Commission (the "IPUC"), acquires energy
efficiency and peak reduction resources as an alternative to the acquisition of supply-side
resources. These resources assist the Company in efficiently addressing load growth and
contribute to the Company's ability to meet system peak requirements. Company energy
efficiency and peak reduction programs provide participating Idaho customers with tools that
enable them to reduce or assist in the management of their energy usage, while reducing the
overall costs to Rocky Mountain Power's customers. These resources are a valuable component
of Rocky Mountain Power's resource portfolio and are relied upon in resource planning as a least
cost alternative to supply-side resources.
Rocky Mountain Power currently offers seven energy efficiency and peak reduction programs in
Idaho. In 2010, costs associated with these programs were and are being recovered through the
Customer Efficiency Services Rate Adjustment (Schedule l9l), with the exception of the Load
Control Service Credits which were paid to participants of the irrigation load control programs
(Schedule 72 and72A) and recovered through general rates. Effective December 28,2010, the
IPUC directed the Company to recover all Schedule 72A costs through general rates, (Order No.
32196). The results of Rocky Mountain Power's Idaho energy efficiency and peak reduction
programs for the reporting period of January l, 2010 through December 31, 2010 are
summarized in Table I below.
Table 1: Total Portfolio Performance
(Note: See notes for Table 2 for explanation of Gross Savings and line loss assumptions)
Participation in the irrigation load control programs increased from285.2 MWr in 2009 to 308.1
MW in 2010. Overall first year energy savings for 2010 achieved through energy efficiency
I Sum of the average years of billing demand for June. July and August for participating loads at the meter values
(Value atsite282.5, Gross up for Line Losses at9.06Yo: 308.1).
2010 Total Portfolio Performance
System Benefit Revenues Collected
System Benefit Expenditures(Excludes lrrisation credits)
otal Expenditures Including Irrigation Credits
MW Under Control (Gross at Generation)
kWh/Yr Savings (Gross at Generation)
kWh/Yr Savings (Gross at Site)
5.939,833
7,515,026
15,615,708
308. I
13.09s,s03
t1.962.957
UCT
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Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
programs, decreased approximately 20 percent while Customer Efficiency Services expenditures
increased l4 percent.
At the end of 2010, the Customer Efficiency Services balancing account had an unfunded
balance of $ 3,845,843.
During 2010, the Company completed process and impact evaluations for several Idaho
programs including the Home Energy Savings, Refrigerator Recycling, Energy FinAnswer,
FinAnswer Express and Agricultural Energy Services programs for program years 2006 to 2008.
The evaluation work was being completed by an independent evaluator. Final reports for the
evaluations are available at r.vr.r.lv.pacificorp.oorn/es/dsnr/idaho.html
Rocky Mountain Power's energy efficiency and peak reduction portfolio was cost effective
under four of the five cost effectiveness tests based on 2010 results. The Ratepayer Impact Test
(RIM) benefit/cost ratio of less than 1.0 indicates that the portfolio put some upward pressure on
overall rates (all things being the same) due to a reduction in Company kWh sales as a result of
the energy efficiency.
For the period January l, 2010 through December 31, 2010, energy efficiency and peak
reduction acquisitions for all programs produced an estimated $19.5 million in net benefits over
the life of the savings on a Total Resource Cost basis.
2010 Performance and Activity
Program and Sector level results for 2010 are provided on the following table2. Program
Schedules are noted in parenthesis in the table.
Table 2: Energy Efficiency and Peak Reduction Annual Results
Rocky Mountain Power
Exhibit No. t Page 7 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
7,515,026
8,100,681
15,615,708
Total System benefit Expenditures - All Programs
Load Control Participation Credits 2010
Total ldaho Progr:am Expenditures
$
s
2 Savings values in this table are shown prior to any net-to-gross adjustment. The values at generation include line
losses between the customer site and the generation source. The Company's line losses by sector are 9.96 percent for
residential, 9.33 percent for commercial and 9.06 percent for industrial. These values are based on the Company's
2007 Transmission and Distribution Loss Sody by Management Applications Consulting published in October
2008.
Idaho Annual Results for 2010
Prosram Units
kw
(at site)
kWYr
Savings
(at senerator)
Program
Exoenditures
Irrigation Load Control (72 and 72Al 2.3rC 282.500 308.080 $ 4283.393
Total Load Control 2.316 282.500 308.080 $ 4.283.393
Prosram Units
kwh,/Yr
Savings
(at site)
kWh/Yr
Savings
(at gene rator)
Program
Exoenditures
Low Income Weatherization (21)43 71346 78.448 $ 133,673
Refrigerator Recycling (l l7)788 1.035,567 1.138,658 $ 165,801
Home Energy Savines (118)6.40C 3.330,684 3.662254 $ 1.305,014
Total Residential 7,231 4,437,597 4,979,360 $ 1,604,488
Enersy FinAnswer (125)C 0 0 $ 47203
FinArswer Express ( I 15)44 3,454,421 3,776,587 $ 513,478
Total Commerrcial 44 3,454,427 3,776,587 $ 560,681
Enersv FinAnswer (125)IC 1.475.439 r.609.040 $ 321.983
FinAnswer Express ( I l5)2 80,325 87,598 s 107,012
Aericultural Energy Services ( I 55 )155 2.515.169 2.742.918 $ 637,009
Total Industrial 167 4,070,933 4,439,556 $ 1,066,004
Market Transformation
Northwest Enerry Efficiency Alliance 0 0 $ 461
Iotal Enerpy Efficiencv 11,962,957 r3.095.s03 $ 3.231,633
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Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Major Trends and Activities
In 2010, the Company realized increases and decreases in energy efficiency and peak reduction
acquisitions in a variety of sectors and programs. At a sector lever, the Residential Sector
realized 75 percent higher savings on a kWh/year basis compared to 2009, and the combined
business and agricultural sectors delivered 18 percent more kWh/year savings than in 2009.
There were no savings realized from Northwest Energy Efficiency Alliance in 2010 which
resulted in a decrease ofthe overall first year energy savings.
Expenditures related to program delivery increased in 2010 as compared to 2009. Overall
expenditures for energy effrciency and peak reduction programs (excluding Irrigation Load
Control participation credits) increased by 17 percent compared b 2A09. When irrigation load
control participation credits are included, expenditures increased by 14 percent in 2010
compared to 2009. At a sector level, the residential sector expenditures increased by 78 percent,
business and agricultural sectors increased by 14 percent and peak reduction increased by 12
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 Total Resource Cost Test (PTRC) which includes a l0 percent additional
benefit for demand-side resources. Total Resource Cost Test (TRC)
2. Utility Cost Test (UCT)
3. Ratepayer Impact Test (RIM)
4. Participant Cost Test (PCT)
The PTRC (also referred to as the TRC * Conservation Adder) is a variation of the TRC test. It
includes a 10 percent benefit adder to account for non-quantified benefits of conservation
resources over supply-side alternatives. This is consistent with Northwest Power Planning and
Conservation Act.
The TRC compares the total cost of a supply side resource to the total cost of an energy
efficiency program resource, including costs paid by the customer in excess of the program
incentives provided. This test is used to determine if an energy efficiency program is cost
effective from a total cost perspective.
The UCT, also referred to as the Program Administrator Test compares the portion of the
resource costs paid directly by the Company and recovered through the tariff rider revenues. This
test is useful in determining the cost effectiveness of the resource from the Company's
perspective; however it does not account for the portion of the cost that is borne directly by
customers.
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Case No. PAC-E-14-07
\Afitness: Kathryn C. Hymas
The RIM test determines the impact an energy efficiency program has on rates. The ultimate
objective ofan energy efficiency program is to encourage customers to use less energy, thereby
reducing energy sales. The RIM test accounts for the lost revenues to the utility and associated
kWh sales reductions. The net impact of these reductions canput upward pressure on rates even
when total costs and utility costs are lower with a successful energy efficiency program than with
a supply-side alternative. One challenge with the RIM test however is that its more sensitive than
the other tests to differences between long-term projections of marginal costs and long-term
projections of rates, two cost streams that are difficult to quanti$ with certainty.
The PCT3 test compares the portion of the resource cost paid directly by participants to the
savings realized by the participant. For the PCT test, bill savings are the realized benefit of
energy efficiency rather than the avoided supply-side costs.
The results for each test are provided at several levels:
1. Overall portfolio level, consolidation of all Company delivered programs
2. Load control and energy efficiency program portfolio
3. Residential and non-residential energy efficiency program portfolio
4. Individual program
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.
3 The calculation of the PCT methodology has changed from previous calculations. For prior cost-effectiveness
analyses, the vendor used Slick Dice, an Excel based cost-effectiveness model. The vendor is now using DSM
Portfolio Pro, which handles all of the analysis programmatically. A minor difference between the two models
impacts how the PCT is calculated. Slick Dice calculated PCT costs as the out-of-pocket costs and PCT benefits as
avoided bills. DSM Portfolio Pro uses the full incremental cost of the measures for PCT costs; benefits are
calculated as avoided bills plus the utility incentive. Both are valid approaches and result in the same net benefits.
The approach used in DSM Portfolio Pro more strictly adheres to the California Standard Practice Manual and
avoids B/C ratio issues caused by $0 costs.
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Program Evaluation
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 energy
effrciency and peak reduction porrfolio.
Table 3: Program Evaluation Timeline
Program
Evaluation
Type Status
Anticipated
Year
Complete
Program
Year(s)
Evaluated Evaluator
llome Energy Saver Process and
Impact Planning 20fi 2009-20t0 To Be Determined
See Ya Later Refrigerator Process and
Impact Planning 20Ir 2009-2010 To Be Determined
Low Income Weatherization Process and
Impact Complete 201t 2007-2009 Cadmus
Low Income Weatherization
(Pending application to remove
program evaluation requirement)
Process and
Impact Planning 2013 2010-2012 To Be Determined
Energy FinAnswer Process and
Impact Planning 2012 2409-2011 To Be Determined
FinAnswer Express Process and
Impact Planning 2012 2009-201t To Be Determined
Irrigation Energy Savers Process and
Impact Planning 2012 2009-2011 To Be Determined
Irrigation Load Control Process and
Impact Planning 2012 2011-2012 To Be Determined
Irrigation Load Control lmpact Complete 20tt 2009-2010 Cadmus
During 2010, the Company received third-party 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 results of these
evaluations are available on the Company web site at http://rvr,r,r.r,.pacificorp.corniesldsm.html for
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Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
public viewing. Findings from these evaluations will be key inputs to ongoing program design
and modification as well as inputs to future cost effectiveness determinations.
Company Filings with the Idaho Public Utilities Commission
The Company made several filings with the Commission regarding its energy efficiency and
peak reduction programs during 2010. Summary information concerning these filings is provided
below.
On February 25, 2010, Rocky Mountain Power filed an application with the Commission
requesting to increase the Customer Efficiency Services rate, which is administered through
Schedule 191. This matter was subsequently assigned to Case No. PAC-E-10-03. Through the
application, the Company proposed the collection rate be increased from 3.72 percent to 5.85
percent effective May l, 2010. The increase was requested to facilitate the funding of ongoing
demand-side management expenditures in Idaho and to reduce an unfunded balance that had
accrued in the demand-side management balancing account. On June 30, 2010, the Commission
issued an order approving an increase in the collection rate to 4.72 percent effective July l, 2010.
On March 15. 2010, the Company submitted its 2009 Idaho Demand-Side Management Annual
Report with the Commission.
Rocky Mountain Power submitted Tariff Advice No. 10-02 with the Commission on July 14,
2010 proposing modifications to the Irrigation Load Control Credit Rider program, which is
administered through Schedule 72. This filing was subsequently revised by the Company
through a filing submitted with the Commission on August20,2010. Through Tariff Advice No.
10-02, the Company proposed various modifications to program administration and revisions to
improve the clarity of the tariff language and to align tariff language with program operations.
The Commission approved the tariffrevisions effective August 30, 2010.
On December 16, 2010, Rocky Mountain Power submiffed Tariff Advice No. 10-03 with the
Commission proposing modifications to the FinAnswer Express program, which is administered
through Schedule 115. The primary purpose of this filing was to align progmm qualifications
with changing energy codes. The Commission approved the modifications proposed through this
filing with an effective date of January 15, 2011.
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Rocky Mountain Power
Exhibit No. 1 Page 12 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Peak Reduction Program and Activity
Peak Reduction programs assist the Company in balancing the timing of customer energy
requirements during heavy use hours; deferring the need for higher cost investments in delivery
infrastructure and generation resources that would otherwise be needed to serve those
requirements for a select few hours each year. These programs help the Company maximize the
efficiency of the Company's existing electrical system and reduce costs for all customers.
Programs targeting capacity related resources are often specific to end use loads most prevalent
in a given jurisdiction, such as the agricultural pumping loads in the Company's Idaho service
territory. The Company offers two peak reduction programs in Idaho; a pre-schedule and on-call
or dispatchable irrigation load control program. For the purpose of this report the two programs
are being combined and evaluated as one program.
Table 4z Load Management Portfolio Performance
2010 Load Management Portfolio
kW Under Control (Gross - At Gen)
kW Under Control (At Site)
Total Expenditures
Particfation Credits
Program Cost Effectiveness
Levelized Cost ($/kWh)
Performance
308,080
292,500
s 12,384,074
$ 8,100,681
PTRC
11
Rocky Mountain Pow6r
Exhibit No. 1 Page 1 3 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Irrigation Load Control (Schedule 72 and72A)
Irrigation Load Control (Schedules 72 & 72A) 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 a participation credit.
A summary of the program performance, expenditures, participation and cost effectiveness
results are provided in table 5:
Table 5: Irrigation Load Control Program Performancea
Additional information regarding major trends and activities, program evaluations, and plans for
the irrigation load control programs are available in the 2010 ldaho Irrigation Load Control
Quantitative Review (Appendix 2) dated January 7,2011.
Major Trends and Activities
During 2010, participating sites increased l3 percent which increased MW under control savings
by 8 percent when compared to 2009. As a result, the participation credits and program
expenditures increased 12 percent respectively from 2009 to 2010.
o th" 2OOg report used MW under management of 285.5 in the calculation of program benefit to cost ratios. A
scheduling resffiction was implemented in 2010 to accommodate the Grid control voltage limitations. While this did
not impact hourly realization rates, it did have a significant effect on the difference between the nominal loads and
the aggregated reductions achieved. In 2010, the maximum hourly load reduction was 156 MW (Calculation - Gross
up for Line Losses at9.06%o:170.1) for all Idaho irrigation program loads. See Impacts of Rocky Mountain
Power's Idaho Irrigation Load Control Program evaluation from Cadmus. wrvw.pacificorp.corrv-es/dsrn/idaho.html
2010 Irrigation Load Control Program Performance
MW Under Control (Gross at Gen)
Expendihres - Total
Participation Credits
Program Operations Expense
P artic fation (Customers )
Particfiation (Sites)
Program Cost Effectivene ss
Levelized Cost ($/kWh)
Lifecvcle Revenue I
308. I
12,384,074
8,100,681
4283,393
878
2,316
PTRC
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Rocky Mountain Power
Exhibit No. 1 Page 14 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Cost Effectiveness
The program was cost effective from all perspectives. Appendix I provides detailed inputs used
in the cost effectiveness analysis of this program.
Program Evaluation
See comments under the Program Evaluation heading in the 2010 Perfornance and Activities
section of this report for evaluation activities related to this program.
Plans for 2011
The company has entered into a stipulation with the Idaho Irrigation Pumpers Association and
the Idaho Public Utilities Commission staff related to the structure and operation of the
company's Dispatchable Irrigation Load Control Credit Rider Program (Schedule 72A.) If
approved by the Idaho Public Utilities Commission the following changes will be implemented:o participation of the program will be restricted for the 201 I and 2012 control period,
o the terms conditions related to customers electing to opt out of control events will be
changed, ando The incentive payment will be reduced for the 2011 control period.
13
Rocky Mountain Power
Exhibit No. 1 Page 15 of495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Energy Efficiency Programs and Activity
Energy efficiency programs deliver sustainable energy savings by improving the efficiency of
equipment such as motors, lighting and cooling equipment. Energy efficiency is also delivered
through improved weatherization of existing buildings, improving the design features of new
facilities by ensuring they are constructed to exceed code. In the industrial sector, improvements
in industrial equipment or processes can also improve energy utilization and deliver long term
energy effrciency resources. Replacement of existing functional equipment, replacement of
equipment at the end of its useful life and improvement opportunities all provide opportunities to
deliver energy effrciency resources. While each type of opportunity has unique challenges,
improvements in these areas all deliver long term energy savings over the life of the installed
equipment.
To deliver resources from these different opporhrnities, the Company offers six energy efficiency
programs; three targeted to residential customers and three targeted to business customers. While
customers may receive only one incentive per project or piece of equipment, the programs are
designed to work in a coordinated fashion and provide complementary services (i.e. recycle an
existing refrigerator after buying a new Energy Star model) or different incentive options (i.e.,
Energy FinAnswer incentives at the time a project is completed). Some programs or program
features are specifically designed to capture lost opportunities (the Design Assistance provision
in Energy FinAnswer), while other programs target retrofit or replacement opportunities in
existing structures (i.e., FinAnswer Express and Home Energy Savings).
Results for the 2010 Energy Efficiency Portfolio are presented in the following table:
Table 6: 2010 Energy Efficiency Portfolio Performance
2010 Energy Efficiency Portfolio Perforrnance
System Benefit Expenditwes
Energy Effrciency First Year Savings MWh/Yr (Gross at Generation) 13,095.503
Energr Efficiency First Year Savings MWh/Yr (at Site) 11,962,957
PTRC TRC UCT RIM PCT
P ortfolio Cost Effectivenes s
Levelized Cost ($/kWh)
Lifecycle Revenue Impact ($/k
$ 0.0s21
s 0.0000417
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Rocky Mountain Power
Exhibit No. 1 Page 16 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Residential Bnergy Efficiency Programs and Activity
Home Energy Savings Program (Schedule 118)
The Home Energy Saver Incentive program (Schedule ll8) provides a broad framework to
deliver incentives for more efficient products and services installed or received by Idaho
customers in new or existing homes, multi-family housing units or manufactured homes. The
program is delivered through a third party administrator hired by the Company. Program
information is available to the public at the program's web site at
lrttp:/iwrarv.homeenergysaviugs.net/ldaholidaho_horne.html and can also be accessed through
http://wrvrv.rock.vmountainporver.net/envlepi.html, the Company's Idaho energy efficiency
program website.
Eligible program measures include: clothes washers, 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: (l) 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.
Summary of the program results for 2010 are provided in the table below:
Table 7: Home Energy Savings Program Performance
10 Home Energy Savings Program Performance
Wh/Yr Savings 2010 (Gross - At Gen)
Wh/Yr Savings 2010 (Gross - At Site)
3,662,254
3.330,684
$ 1,30s,014
$ 828,401
PTRC TRC UCT RIM PCT
Cost Effectiveness
lized Cost ($/kwh)
fecycle Revenue Imoact ($/kwh) S 0.000103
15
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Witness: Kathryn C. Hymas
Details of 2010 measure level participation and savings are provided on the following table:
Table 8: Home Energy Savings Measure Performance
2010 Home Enersv Savinss Measure Performance
kWh/Yr
SavingsUnit (Gross -
Ilome Energy Savings Measures Measurement # of Units Participants Site)
Clothes Washer-Tier One Units 212 212 50,427
Clothes Washer-Tier Two Units 1,167 1,167 280,164
Clothes Washer Recycling Units 0 0 0
Dishwasher Units 521 521 19,622
Electric Water Heater Units 99 99 8,979
Evaporative Cooler (Portable) Units 0 0 0
Evaporative Coolers (Permanently Installed) Units I I 325
Refrigerator Units 460 460 44,850
Room AC Units 0 0 0
Insulation: Attic sq feet 1,361,168 1,080 1,961,621
Insulation: Floor sq feet 21,667 22 19,517
lnsulation: Wall sq feet 9,400 14 21,261
Windows sq feet 14,981 129 29,128
CAC Tune up Projects 98 98 2,940
CAC (15 SEER) Units 0 0 0
CAC Install Units 0 0 0
CAC Sizing Projects 0 0 0
Duct Sealing-Electric Projects 34 34 1,360
Duct Sealing-Gas Projects 28 28 1,120
Duct Sealing & Insulation Projects 0 0 0
Heat Pump Tune-Up Units 0 0 0
Heat Pump Conversion Units 0 0 0
Heat Pump Upgrade Units I I 811
Water Source HP (Air Source HP Upgrade) Units 0 0 0
Water Source HP (Heat System Conversion) Units 0 0 0
Ceiling Fans Units 13 7 1,391
Fixtures units 84 38 7,728
CFls-Twisters Bulbs 24,892 2,489 879,442
CFls-Specialty Bulbs Bulbs 0 0 0
Totals
kWh/Yr Sav
1.434,825 6,400 3,330,684
at Generation 3.662.2
(Note: CFL participation is assumed at 10 CFLs per participant.)
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Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Major Trends and Activities
The Home Energy Saver Incentive progmm savings in 2010 increased 147 percent as compared
to 2009, while the expenditures increased approximately 120 percent.
The large increase in participation was seen in early 2010 from an upswing in weatherization
activity that began in late 2009. The upswing was the result of a few weatherization contractors
adjusting their pricing and installations practices so that work was priced at or below the existing
incentives. After a review of the incentive levels and recent installation cost data the Company
adjusted incentive levels based on heating fuel source. a more relevant screen for electric savings
and benefits. After the required noticing period on March 20, 2010 the incentives for
weatherization measures were lowered, improving the measure economics and bringing
insulation measure activity in line with the change in market prices for the remainder of 2010.
Appliance and lighting activity also saw steady increases during 2010. Appliance measure
participation increased 33 percent from steady growth in the ENERGY STAR appliance market
and increased program visibility in the territory. Funded by the American Recovery and
Reinvestment Act of 2009 the Idaho State Appliance Rebate program offered incentives on
appliances. Customers could also receive incentives for the same appliances through the Home
Energy Savings program. The combination of both incentives increased clothes washers by 30
percent and dishwashers by 26 percent for the Home Energy Saver Incentive program over the
prior year. A program representative dedicated to field visits to local retailers and contractors
made an increasing number of trips in 2010, giving the program a more consistent presence in
the region.
CFL lighting activity saw a 20 percent increase in bulb sales by focusing on smaller and mid-
level retailers like Family Dollar, Mickelsons and independently owned True Value Hardware
stores who previously had not been involved in the program. By improving relationships with
retailers the program was able to maximize available products under Idaho's specific tariff
structure. In 2009, there were l9 products by the close of 2010, there were 40.
Representatives attended the Eastern Idaho Fair in September 2010 to promote program services
and incentives, and provide general awareness of high efficiency equipment, lighting and
weatherization options. The Eastern Idaho Fair attracts upwards of 210,000 people across 16
eastem Idaho counties. This is the largest outreach event the program attends.
Cost Effectiveness
The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix I provides detailed inputs used in the cost effectiveness analysis of this program.
Program Evaluation
Refer to the Program Evaluation in the 2010 Perforrnance and Activities section of this report for
evaluation activities related to this program.
17
Rocky Mountain Power
Exhibit No. 1 Page 19 of495
Gase No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Plans for 2011
The Home Energy Saver Incentive program is implementing a localized marketing strategy to
increase awareness and participation. This strategy includes: attend more community events,
provide more training and support for HVAC and weatherization contractors, visiting retail
partners to provide additional training support, and marketing materials. Partnerships with other
state and utility programs, trade associations and government offices will also be explored.
During 2011, the Company plans to make modifications to the Home Energy Saver Incentive
program including changes to lighting, appliances, weatherization, heating and cooling measures.
The proposed changes are designed to improve program performance, enhance participation and
align with current codes and standards, and revise incentive levels to be more competitive with
other utilities in the region.
18
r*,'[i,"j',,%""#il:'"Xr";
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
See ya later, refrigerator@ (Schedule 117)
The Residential Refrigerator Recycling Program (Schedule I l7) is available to Idaho residential
customers through a Company contracted third-party program administrator. Older refrigerators
and freezers which are less efficient, yet operational, are taken out of use permanently and
recycled in an environmentally responsible manner. The program's objective is to permanently
retire these older and less efficient refrigerators and freezers from the market and recycle the
units in order to avoid their re-entry or resale on the secondary appliance market. Program
awareness is generated through mass media advertising channels as well as Company
communications such as the program's web site, bill stuffers, and customer newsletters. In
addition to free pick-up and a nominal cash-incentive, participants receive an energy efficiency
packet consisting of ENERGY STAR@-certified compact fluorescent light bulbs, a
refri gerator/ fr eezer therm ometer, and energy educati on materi al s.
A summary of the program results for 2010 are provided in the table below.
Table 9: See ya later, refrigerator@ Program Performance
Details of 2010 measure level participation and savings are provided on the following table:
Table 10: See ya later, refrigerator@ Results
Refrigerator Recycling
Measure Unit Count
Per Unit
Savings
(kWh/Yr)
Gross Savings
(kWh/Yr)
Refrigerator 629 1.149 722,721
Freezer 159 1^590 252,825
Iotal Units Recvcled 788 975,546
Enerw Savines Kits 741 81 60.021
Total (At Site)r.035.567
Total (At Generation)1,138,658
2010 See ya later, refrigerator@ Program Performance
kWh Savings 2010 (Gross - At Gen) 1,138,658
kWh Savings 2010 (Gross - At Site) I,035,567
Expenditures $ 165,801
Incentives Paid S 23,640
PTRC TRC UCT RIM PCT
Program Cost Eflectiveness
Levelized Cost ($/kWh)
Lifecvcle Revenue Impact ($/kwh) $ 0.000072041
19
."^,,[ rl,,i:$ii :,"x,"J
Case No. PAC-E-1+O7
Vvitness: Kathryn C. Hymas
Major Trends and Activities
While program participation for 2010 increased by 9 percent as compared to 2009, program
expenditures increased 53 percent over the same period. The increase in program expenditures
were primarily driven by the multi-year process and impact evaluations completed in 2010.
A direct mail postcard with a refrigerator magnet intended to increase customer program
awa.reness and provide a lasting call to action was mailed to 30,000 Idaho customers from the
highest performing zip codes in previous years, generating a year-end increase in activity.
Environmental Attributes
In terms of the impact of the program on the environment, processing the 788 units resulted in
the recycling of more than 100 thousand pounds of metal,20 thousand pounds of plastics, half a
ton of tempered glass and the capture, recovery or destruction of more than 1,000 lbs of ozone
depleting chlorofluorocarbons (CFC) and hydrofluorocarbons (HFC), commonly used as
refrigerants. The carbon dioxide (CO2) and carbon dioxide equivalent (CO2e) avoided from the
atmosphere was equal to 6,500 tons.
Cost Effectiveness
The 2010 See ya later, refrigerator@ program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix I provides detailed inputs used in the cost effectiveness
analysis of this program. .
Program Evaluation
Refer to the Program Evaluation heading in the 201 0 Perforrnance and Activities section of this
report for evaluation activities related to this program.
Plans for 20Ll
Several new program design features will help increase program participation starting in spring
of 2011. Based on successful direct mail campaigns in 2010 more direct mail will be used in
2011. Direct mail postcards with a refrigerator magnet advertising the program will be sent out
in two different batches in 2011. The program is working with Sears, Best Buy, Lowe's and
other appliance retailers in Idaho to allow customers to have new units delivered and the old
units picked up at the same time. This allows home owners to schedule only one appointment for
the delivery of their new appliance and the pickup of their old one. Cross program coordination
with the Home Energy Savings program will improve coordination with retailers on ENERGY
STAR appliances, making it more convenient for customers to participate in the See ya later,
refri gerator@ pro gram.
20
Rocky Mountain Power
Exhibit No. 1 Page 22 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Low Income Weatherization (Schedule 21)
The Low Income Weatherization Services program (Schedule 2l) is available through a
partnership with Eastem Idaho Community Action Partnership (EICAP) in Idaho Falls and South
Eastern Idaho Community Action Agency (SEICAA) in Pocatello. These partnerships allow for
leveraging of Company funding with federal grants available to EICAP and SEICAA, increasing
the number of homes served. Rocky Mountain Power's funding in 2010 provided rebates that
covered 75 percent ofthe cost ofapproved energy efficiency measures.
Income eligible households receive energy efficiency services at no cost. Participants can be
either homeowners or renters residing in single-family homes, manufactured homes and
apartments.
Table 9 summarizes the program results for 2010. The reported energy savings is based on
measured savings documented in an analysis dated August 30, 2006 completed by
Quantec/Cadmus. Program expenditures totaled $133,673. 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 43 qualifl,ing
homes in 2010 with an average program cost per home of $3,109.
Table 11: Low Income Weatherization Performance
Low Income Weatherization Performance - Idaho
kWh/Yr Savings (Gross at Site)
kWhYr Savings (Gross at Gen)
Expenditures - Total $
71.346
78,448
133,673
Panicipation - Total # of Completed/Treated Homes 43
Number of Homes Receiving Specific Measures
Ceiling Insulation
Floor Insulation
Wall Insulation
Replacement Windows
Storm Windows
Duct Insulation/Sealing
Insulated Doors
Attic Ventilation
Infiltration
Water Pipe Insulation and Sealing
Water Heater Repair/Replacement
Fumace Repair/Tune-up/I i lters
Furnace Replacement
Compact Fluorescent Light bulbs (CFL)
Health & Safetv Measure
t7
6
J
t6
I
5
t4
14
t9
3l
4
7
J
43
l5
Program Cost EfFectiveness
Levelized Cost ($/kWh)
Lifecvcle Revenue Imoact (S/kWh .0000rsr27
TRC UCT RIM PCT
21
.,n,'[fY,i:Sil :'"X'"J
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Major Trends and Activities
Participation during 2010 decreased by 62 percent compared to 2009. Participation numbers can
be greatly affected by the timing of when agency invoices are received and processed making
completions in a year seem significantly high or low. Program savings decreased 63 percent and
expenditure increased by 32 percent in 2010 compared to 2009. Expenditures were aflected by a
$7,500 payment for kits that will be used in the agencies energy education program, and costs
related to a program evaluation.
Cost Effectiveness
An evaluation of Low Income Weatherization Services Optional for Income Qualifying
Customers program was completed in 20ll by a third party administrator based on program
activities in2007 through 2009.
The program evaluation performed includes the review of processes and irnpacts. It provides
kWh savings determined through billing analyses, as well as estimates for non-energy benefits.
The Company's portfolio of energy efflrciency programs is cost effective, but the evaluation
indicates that Schedule 2l is not cost-effective from the Total Resource Cost (TRC), Utility Cost
(UCT) or Ratepayer Impact (RIM) perspectives unless non-energy benefits are included.
The Company recognizes the importance of our Low Income Weatherization Program and the
benefit to our customers by reducing kWh usage and helping to make participant's bills more
affordable, as well as increasing their comfort. However, as described in the Low-Income
Weatherization program evaluation, due to many factors the program is not cost-effective. To
this end, the Company has a pending application requesting the Commission acknowledge the
program as an acceptable part of the Company's program portfolio, and find that it should
continue.
Program Evaluation
Refer to the Program Evaluation heading in the 2010 Perfonnance and Activities section of this
report for evaluation activities related to this program.
Plans for 2011.
The Low Income Weatherization program was revised on December 28,2010. Per an order by
the Commission, Rocky Mountain Power's reimbursement on eligible measures increased from
75%o to 85oh and the maximum annual reimbursement to our partnering agencies increased from
$150,000 to $300,000. With these changes, we anticipate an increase in homes treated. The
Company believes that the cost-effectiveness will be further eroded with the recent increase to
cost sharing requirements, therefore the Company has a pending application requesting the Idaho
Public Utilities Commission remove any future obligation for program evaluations.
22
.-^,',T"r"Y,T"#il:'"ff;
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Non-Residential Energy Efficiency Programs and Activity
Energy FinAnswer (Schedule 125)
The Energy FinAnswer program is offered to commercial (buildings 20,000 square feet and
larger) and industrial customers. The program provides Company-funded energy engineering,
incentives of $0.12 per kWh of first year energy savings and $50 per kW of average monthly
demand savings up to a cap of 50 percent of the approved project cost. The program is designed
to target comprehensive projects requiring project specific energy savings analysis and operates
as a complement to the more streamlined FinAnswer Express program. In addition to customer
incentives, the program provides design team honorariums (a finder fee for new projects) and
design team incentives for new construction projects exceeding current Idaho energy code by at
least l0 percent.
A summary of the program results are provided in the table below:
Table 12: Energy FinAnswer Program Performance
Details of 2010 savings by type of measure are provided on the following table:
Table 13: Energy FinAnswer by Measure Type
Energy FinAnswer kWh/Yr Savings (at site) by Measure Type
Compressed Air 406,336
Lighting 26,665
Motors 647,994
Refrigeration 394,Uq
r47s,439
kWh/Yr Savings 2010 (Gross - At Gen)
kWh/Yr Savings 2010 (Gross - At Site)
Expenditures
Incentives Paid
Program Cost Effectiveness
Levelized Cost ($/kWh)
Lifecycle Revenue Impact ($/kwh) $ 0.0000008314
1,609,040
1,475,439
$ 369,186
$ 107,598
PTRC TRC UCT RIM PCT
0.0352
23
,"n, o[i,"j', 1"#i! :,"XrT
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Major Trends and Activities
A total of ten Energy FinAnswer projects were cornpleted in 2010 compared to eight in 2009.
Program specific energy savings and expenditures remained constant during 2010 compared to
2009. The Company continues to market the program through its Customer and Community
Managers and network of trade allies in concert with the FinAnswer Express program.
Cost Effectiveness
The 2010 Energy FinAnswer program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix I provides detailed inputs used in the cost effectiveness
analysis of this program.
Program Evaluation
Refer to the Program Evaluation heading in the 2010 Perfonnance and Activities section of this
report for evaluation activities related to this program.
Plans for 2011
Continue to monitor actual and forecasted participation and assess the potential impacts of
program modifications similar to those implemented in other markets.
The Company is investigating possible adjustments to program incentives, adjusting the project
cost cap and introducing a program option allowing for savings driven proportionate co-funding
of energy project managers at a customer facility site to assist in the completion of energy
efficiency projects.
24
.-', o[ i,'i'.,[:Si: :,"ffJ
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
FinAnswer Express (Schedule 115)
The FinAnswer Express program (Schedule 1 15) is available to Idaho business customers
excluding those served on Schedule 10, which are eligible for program services through the
Agricultural Energy Services program. The FinAnswer Express program is available to help
customers improve the efficiency of their new or replacement lighting. HVAC, motors, building
envelope and other equipment by providing prescriptive or pre-defined incentives for the most
common efficiency measures listed in the program incentive tables. The program also includes
custom incentives and technical analysis services for measures not listed in the program
incentive tables that improve electric energy efficiency. The program is designed to operate in
conjunction with the Energy FinAnswer program. Although incentives available vary, the
program provides incentives for both new construction and retrofit projects.
The program is primarily marketed through local trade allies who receive support from Company
provided sales and training team. The lists of participating vendors posted on the Company
website include 18 lighting, 30 HVAC, 24 motor, and 3 other equipment trade allies.
A summary of the program results are provided in the table below:
Table 14: FinAnswer Express Program
Details of 2010 savings by type of measure are provided on the following table:
Table 15: FinAnswer Express by Measure Type
FinAnswer Express
Lighting
Non-Lighting
kWh/Yr Savings
1,147,600
(at site) by Measure Type
32%
68%2,387,152
3,534,752
kWh/Yr Savings 2010 (Gross - At Gen)
kWh/Yr Savings 2010 (Gross - At Site)
Expenditures
Incentives Paid
Program Cost Effectiveness
Levelized Cost ($/kWh)
Lifecycle Revenue Impact ($/kwh) $ 0.000085588
3,864,185
3,534,752
$ 620,490
$ 293,098
PTRC TRC UCT zuM PCT
25
*','[ffY.,T""H]:'"X'"J
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Major Trends and Activities
During 2010, savings were significantly higher (322%) than in 2009 primarily a result of the
completion of several new construction projects occurring in the education sector. The new
construction projects were primarily driven by one customer undergoing an expansion phase,
2010 savings levels will likely not be repeated in 201l.
On May 6,2010, Rocky Mountain Power provided lighting and mechanical/nonlighting program
training in combination with the Northwest regional trade ally network lighting training in Idaho
Falls, 60 individuals attended.
Cost Effectiveness
The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix I provides detailed inputs and assumptions used in the cost effectiveness analysis of
this program.
Program Evaluation
Refer to the Program Evaluation heading in the 2010 Perforrnance and Activities section of this
report for evaluation activities related to this program.
Plans for 2011
The Company plans to file program changes in 2011 to add new measure categories such as
dairy farm, small compressed air, appliances, and food service to the program and also update
existing measures.
The Company plans to provide marketing and trade ally outreach to target customers with Tl2
fluorescent lighting to provide information on changes in federal lighting standards coming in
2012 and the limited time opportunity to upgrade to higher efFrcient lighting before the standards
take effect while current incentives are available.
26
.*, o[i,?, li$il :,"x,";
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Agricultural Energy Services (Schedule 155)
Agricultural Energy Services, marketed as Inigation Energy Savers (Schedule 155), was
available in 2010 to Idaho irrigation customers taking retail service on Schedule l0 through a
Company contracted third-party program administrator. The program design is intended to be the
energy efficiency complement to the Irrigation Load Control programs offered under Schedules
72 &72A. The 2010 program included the following customer service and measure components:
Equipment Exchange - Provides new standard brass sprinkler nozzles, gaskets, and
drains to replace worn equipment on hand lines, wheel lines and solid set sprinklers
systems.
Pivot and Linear Equipment Upgrades - Incentives are provided for certain pivot and
linear system measures including sprinkler packages, pressure regulators, and drains. The
list of prescriptive incentives is not designed to be exhaustive and other pivot measures
are eligible for incentives if energy savings can be calculated and the customer incurs
costs to make the changes.
System Consultation - This service provides a simple site specific audit of a customer's
irrigation system to promote irrigation water management and identify energy savings
opportunities. This consultation provides information prior to a full pump test.
Pump Testing - The pump test includes directly measuring pump lift. flow. electrical
demand, and system pressures and is performed after the pump has been screened and the
owner's financial investment criteria understood.
System Analysis - The progpm provides energy engineering to help growers quantii/
the costs and savings of their system efficiency upgrades. Often these upgrade decisions
are made in conjunction with operational production change considerations impacting a
growers equipment needs. Lrcentives are based on a standard formula tied to costs and
first year energy savings.
A summary of the program results for 2010 are provided in the table below.
Table L6: Agricultural Energy Services Program Performance
2010 Agricultural Energy Services Program Performance
kWh/Yr Savings 2010 (Gross - At Gen) 2,742,918
kWh/Yr Savings 2010 (Gross - At Site) 2,515,169
Expenditures $ 637,009
Incentives Paid S 250,924
PTRC TRC UCT zuM PCT
Program Cost Effectiveness
Levelized Cost ($ikWh)
Lifecycle Revenue Impact ($/kWh) $0.000124309
27
Rocky Mountain Power
Exhibit No. 1 Page 29 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Details of 2010 savings by type of measure are provided on the following table:
Table 17: Agricultural Energy Savers by Measure Type
Agricultural Energy Savers kWh/Yr Savings by Measure Type (at Site)
Equipment Exchange & Pivot/Linear Upgrade 1.658.488 66%
System Design 856.681 34%
2-515.169
Major Trends and Activities
The 2010 savings and expenses were 37 percent and 2l percent lower compared to 2009
program savings and expenditures.
During 2010 90 site visits were completed to obtain system information used in either a system
consultation or an energy analysis evaluation as a part of the Agricultural Energy Services
Program. During the same year, 19 post installation inspections were completed to veriff project
installation and energy savings.
The following outreach and event activities were completed for the program in 2010:
Provided a one hour presentations at the Golden West Irrigation Company pivot school
on program components available and potential savings for irrigation pump VFDs on
February 23'd and 24'h, 2010.
Provided a one hour presentation on program components available and potential savings
for irrigation pump VFDs and met with customers at the Rain For Rent customer
appreciation day in Idaho Falls on February 25th,2010.
Operated a booth at the Valley Implement customer appreciation day in Preston on
February 25th,2olo.
Provided the updated program manual and 2010 program applications to all of the
participating dealers and followed up with phone calls to discuss program updates.
Cost Effectiveness
The program was cost effective from all perspectives except the Ratepayer lmpact Test.
Appendix I provides detailed inputs and assumptions used in the cost eflectiveness analysis of
this program.
The last program and impact evaluation determined energy savings at a precision of +551
percent for the equipment exchange and pivot/linear upgrade. The system design category was
calculated at +86 percent precision, both reported at a 90 percent confidence interval. Due to the
wide range of savings calculations, 2009 realization rate of 1.00 was used in 2010 cost
effectiveness tests.
28
='n,o[ffy,[:Si8:'"ffJCase No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Program Evaluation
Refer to the Program Evaluation heading in the 2010 Perforrnance and Activities section of this
report for evaluation activities related to this program.
Plans for 2011
The results of the program evaluation were inconclusive. The program results will be reviewed
with the stakeholders to determine if the program should be modified or suspended.
29
',','[ffY,1""[1]:'"X'"JCase No- PAC-E-14-07
Vwness: Kathryn C. Hymas
Market Transformation - Northwest Energy Efficiency Alliance
The contract with the Northwest Energy Efficiency Alliance was not renewed in 2010 for the
2010-2014 funding cycle. The company is currently evaluating the benefits and costs associated
with this program to ensure Rocky Mountain Power customers in southeastem Idaho are
beneficiaries of the alliance activities.
30
Roclry Mountain Power
Exhibit No. 1 Page 32 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Summary of 2010 Results:
Table 18: Revenues (Schedule 191) by Customer Type
Industrial
Table 19: Expenditures (Schedule 191) by Customer Type
Industrial
Commercial
(Note - Table l7 does not include lrrigation Load Control Service Credits
31
Rocky Mountain Power
Exhibit No. 1 Page 33 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Table 20: Expenditures (Schedule 191) by Type of Program
(Note - Table l8 does not include lrrigation Load Control Service Credits
Table 21: Total expenditures by Type of Program
(Note - Table 19 includes Schedule l9l expenditures and Irrigation Load Control Service Credits
32
Rocky Mountain Power
Exhibit No. 1 Page 34 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Table 22tEnergy Efficiency Expenditures by Customer Type
Industrial
l3o/o
Table 23: Energy Efficiency Results by Customer Type
Industrial
130A
33
.,,,,o[i,"Y.,T:Sil:,"x,"J
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Balancing Account Summary
Energy efficiency and peak reduction activities are funded by revenue collected through
Schedule l9l, Customer Efficiency Services Rate on customer bills. Expenses for energy
efficiency and peak reduction programs are charged as incurred and booked to the balancing
account. The energy efficiency and peak reduction balancing account activity for 2010 is
outlined in the table below.
Table 24: Balancing Account Activity (Schedule 191)
Balance n of l2l3ll09
$ 2,238,820
January
February
March
April
May
une
July
August
September
November
December
2010 totals
Carrying
Charge
1,832.00
1,851.00
2,068.00
2,300.00
2,672.00
3,116.00
3,152.00
3,043.00
2,939.00
2.885.00
2,917.00
3,054.00
Accumulated
Balance
$ 2,1s8,909.32
s 2,285,371.29
$ 2,680,757.26
$ 2,841,442.68
$ 3,573,399.28
$ 3,909,128.21
$ 3,659,174.67
$ 3,646,218.72
$ 3,409,917.77
$ 3,516.484.07
$ 3,487.928.76
$ 3,845,842.53
Monthly Program
Cost - Fixed
Assets Rate Recovery'$ 287.808.96'$ (369,5sr.91i$'$ 455,659.05 '$ (33 1,048.08)'$'$ 698,743.75's (305,425.78f$'$ 439,62r.74'$, (zir,z3fizf $'$ r,074,442.77'$ (345,158.17f$'$ 794.2315r'$ (461,61s.ssf$'$ 602,679.49'$ (855,785.03)'$
'$ 942,866.52'$ (958,865.47f$'$ 429,505.50'$ (668,751.451$'$ 598,206.77'$. (4g4,5rg.47i $'$ 381,355.70'$ (412,828.01f$
'$ 809,904.62'$ (455,044.85)'$
$ 7.s1s.026.38 $ (5.939.833.12) $.00
Column Explanations:
Monthly Proeram Costs - Fixed Assets: Monthly expenditures for all energy efficiency and peak reduction
program activities.
Rate Recoverv: Revenue collected through Schedule l9l, Customer Efficiency Service Rate.
Carr.vine Charee: Monthly "interest" charge based on "Accumulated Balance" of the account. The current
"interest rate" for the Accumulated Balance is I percent per year.
Accumulated Balance: Current balance of the account. A running total of account activities. If more is
collected in "Revenue" than is spent for a given month, the "Accumulated Balance" will be decreased by
the net amount. A negative accumulative balance means cumulative revenue exceeds cumulative
expenditures; positive accumulative balance means cumulative expenditures exceed cumulative revenue.
At the beginning of 2010, the unfunded balance was approximately $2.2 million and increased
by approximately $1,607,000 during 2010. The unfunded balance at the end of 2010 is $3.846
million.
34
Rocky Mountain Power
Exhibit No. 1 Page 36 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Cost Effectiveness:
Introduction
The cost effectiveness of individual programs operated by the Company for 2010 are calculated
using actual expenditures and reported savings. Cost-effectiveness is provided at the individual
program, load management portfolio, residential energy efficiency portfolio, non-residential
energy efficiency portfolio. combined energy efficiency portfolio, and overall energy efficiency
and peak reduction program portfolio levels. Deemed savings estimates where applicable were
the same as those used in the planning estimates, 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 o'site" or at "generation" designation. Line losses are based on the Company's 2007
line loss study. Net-to-gross assumptions are consistent with planning estimates. The energy
savings attributed to each program are shaped according to specific end-use savings (the hourly
calculation of when energy is used for the various end-use measures from which the savings are
derived). Program costs and the value of the energy savings are then compared on a present
value basis with the Company's 2008 Integrated Resource Plan (lRP) 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 cost/benefit analysis of the load management programs are based on the avoided value of
peak or capacity investments. For purposes of calculating program cost-effectiveness no energy
savings are included for the load management programs, only a shift of when the energy is used
away from the peak load hours. The five California Standard Practice Manual cost effectiveness
tests were utilized in the cost benefit analysis for both energy efficiency and load management
programs. Further details are available in Appendix L
35
E,hib,Tff T:S??:'"X,1
Case No. PAC-E-1+07
\ fitness: Kathryn C. Hymas
Key Assumptions for Cost Effectiveness Calculations:
Cost Effectiveness calculations for programs and measures (or measure groups) within each
program will be detailed in the tables in Appendix 1.
Global Assumptions used in all cost eflectiveness calculations include:
Assumption
Discount Rate
Line Losses (Idaho Specific)
Residential
Commercial
Industrial
Source
2OO8IRP
2007 MAC Line Loss Study
2007 MAC Line Loss Study
2007 MAC Line Loss Study
Value
7.40%
9.9550/o
9.326%
9.055o/o
Key elements that go into the cost effectiveness calculation for each program include:
o KWkWh Savings Grosso AdministrativeExpenseso Incentives Paido Total Utility costs - including administration and evaluationo Gross Customer Costso Net To Gross Ratio
o Measure Lifeo IRP Decrement Value
Please reference Appendix l, Cost Effectiveness 2010 Idaho Energy Efficiency and Peak Reduction
Annual Report for additional information on the key assumptions and inputs for cost effectiveness
calculations for each program.
36
Rocky Mountain Power
Exhibit No. 1 Page 38 of495
Case No. PAC-E-'I+07
\Mtness: Kathryn C. Hymas
Appendices:
Appendix 1 - Cost Effectiveness 2010 Idaho Energy Effrciency and Peak Reduction
Annual Report
Appendix 2 - 2010 ldaho Load Control Program Quantitative Analysis
Appendix 3 - The Cadmus Group's Evaluation Report on Rocky Mountain Power's
Irrigation Load Control Credit Rider Program
37
Rocky Mountain Power
Exhibit No. 1 Page 39 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
vRocKYMOUNTATN
YPOWER\ A DTVTSTON OF PACTFTCORP
Appendix 1ffiess
2010 ldaho Energy Efficiency and Peak
Reduction Annual Report
Rocky Mountain Power
Roclry Mountain Power
Exhibit No. 1 Page 40 of 495
Case No. PAC-E-'|+07
Witness: Kathryn C. Hymas
Portfolio and Sector Level Cost Effectiveness
The overall energy efficiency and peak reduction porffolio 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 portfolio and sector results of all five cost effectiveness
tests.
2010 Portfotio and Sector Cost Effectiveness Summary
t Efrectiveness Test
2010 Total Portfolio including Load Control
2010 Total Portfolio excluding Load Control
2010 C&l Enerry Effrciency Portfolio
2010 Residential Enerry Efficiency Porffolio
2010 Inigation Load Control
PTRC TRC
2.613 2.376
1.978 1.798
1.869 1.699
2.124 1.931
3.190 2.900
UCT RIM PCT
1.246 0.913 7.0t0
2.175 0.788 3.298
2.342 0.860 2.726
2.007 0.716 4.090
1.000 1.000 NA
Portfolio and Segment Level Cost Effectiveness Summaries:
The cost effectiveness results for the porffolio 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.
2010 Total Portfolio including Load Control
Total Resource Cost Test (PTRC) +
Conservation Adder
NA $8,1 92,802 $21,409,860 $13,217,058 2.613
Total Resource Cost Test fiRC) No Adder NA $8,192,802 $19,463,509 $11,270,707 2.376
Utility Cost Test (UCT)NA $1 5,615,246 $19,463,509 $3,M8,263 1.246
Rate lmpact Test (RlM)$21,306,792 $19,463,509 ($1,843,283)0.913
Participant Cost Test (PCT)$2,181,898 $15,295,888 $13,113,990 7.010
Lifecycle Revenue lmpacts ($/kwh)NA
Rocky Mountain Power
Exhibit No. 1 Page 41 of 495
Case No. PAC-E-14-07
Ufrtness: Kathryn C. Hymas
2010 Total Portfolio excluding Load Control
Total Resource Cost Test (PTRC) +
Conservation Adder
0.0521 $3,90e,409 $7,731,899 $3,822,490 1.978
Total Resource Cost Test (TRC) No
Adder
0.0521 $3,909,409 $7,028,999 $3,119,590 1.798
Utilitv Cost Test (UCT)0.0431 $3,231j72 $7,028,999 $3,797,827 2.175
Rate lmpact Test (RlM)$8,922,718 $7,028,999 ($1 ,893,719)0.788
Particioant Cost Test (PCT)$2,181,898 $7,195,207 $5,013,309 3.298
Lifecycle Revenue lmpacts ($/kwh)$0.0000417229
2010 C&I Energy Efficiency Portfolio
Total Resource Cost Test (PTRC) +
Conservation Adder
0.0513 $2,242,052 $4,190,015 $1,947,963 1.869
Total Resource Cost Test (TRC) No
Adder
0.0513 $2,242,052 $3,809,1 04 $1,567,053 1.699
Utilitv Cost Test (UCT)0.0373 $1,626,686 $3,809,104 $2,182,418 2342
Rate lmoact Test (RlM)$4,428,646 $3,809,'104 ($619,541)0.860
Particioant Cost Test (PCT)$1,266,986 $3,453,580 $2,186,594 2.726
Lifecvcle Revenue lmoacts ($/kwh)$0.0000256276
2010 Residential Energy Efficiency Portfolio
Total Resource Cost Test (PTRC)
+ Conservation Adder
0.0532 $1,667,357 $3,541,885 $1,874,527 2.124
Total Resource Cost Test (TRC)
No Adder
0.0532 $1,667,357 $3,219,895 $1,552,538 1.931
Utility Cost Test (UCT)0.0512 $1,604,486 $3,219,895 $1 ,61s,409 2.007
Rate lmoact Test (RlM)$4,494,073 $3,219,895 ($1,274,178\0.7'16
Participant Cost Test (PCT)$914,912 $3,741,628 $2,826,715 4.090
Lifecycle Revenue lmpacts ($/kWh $0.0000600654
Rocky Mountain Power
Exhibit No. 1 Page 42 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
2010 Irrigation Load Control
Total Resource Cost Test (PTRC) +
Conservation Adder
$4,283,393 $13,677,960 $9,3%,567 3.19
Total Resource Cost Test (TRC) No Adder $4,283,393 $12,434,509 $8,1 51 ,1 1 6 2,90
Utility Cost Test (UCT)$12,384,074 $12,434,509 $50,435 1.00
Rate lmpact Test (RlM)$12,384,074 $12,434,509 $50,435 1,00
Participant Cost Test (PCT)$0 $8,100,681 $8,100,681 NA
Lifecycle Revenue lmpacts ($/kwh)
Roclq Mountain Power
Exhibit No. 1 Page43 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Program Level Cost Effectiveness
Irrigation Load Control Program - SchedulesT2 and72A
The following tables outline the primary inputs and assumptions utilized in the cost effectiveness
calculations for the program.
m Inputs - Irrigation Load Contrel Value Source and Notes
verage kW Dispatched dwing inigation season (At Site) 156,000 Impact Evaluation -Cadmus 2010
verage kW Dispatched during inigation season (At Gen) 170,126 Calculation - Gross up for Line Losses at 9.06%
frtvarueofDispatchedkw(AtGen) $ 73.0e iljl"'r1l'Jt-ffifrffit bvagreeduponvaluation
fit Value : Avg kW Dspatched muhplied by $73 09 $ 12,434,495 Calculation ($73.09 $&W * 170.126 kW-Yr)
'am Management and Administration Costs $ 4,283,393 Annual costs 2010
ves $ 8,100,681 Annual costs 2010
otal UtiliS, Costs $ 12.384,074 Annual costs 2010
otal Participant Costs NA There are no direct participant costs for the program.
t To Gross Ratio 1.00 Assume 1.0 Net To Crross
Life (Years),O Benefit value is NPV of l0 year benfits from avoided
neration and market purchases.
Total Resource Cost Test (PTRC) +
Conservation Adder
$4,283,393 $13,677,960 $9,394,567 3.19
Total Resource Cost Test (TRC) No
Adder
$4,283,393 $12,434,509 $8,151,1 16 2.90
Utility Cost Test (UCT)$12,3U,074 $12,434,509 $50,435 1.00
Rate lmpact Test (RlM)$12,3U,074 $12,434,509 $50,43s 1.00
Participant Cost Test (PCT)$0 $8,100,681 $8,100,681 NA
Lifecycle Revenue lmpacts ($/kWh)
Discounted Participant Payback (years)
Additional information regarding major trends and activities, program evaluations, and plans for
2011 for the irrigation load control program are available in the 2010 seasonal report 2010 Idaho
Irrigation Load Control Quantitative Review (Appendix l) dated January 7,2011.
u-n,ofi,"L1i$il:,'],1
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
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 lnputs - Home Energy Savings
kWh/Year Savings (at Site) 3,086,839 Annual results 2010 (Gross at Site)
lram Management and Administration Costs $ 476,6L3 Annual costs 2010
ntives S 828,401 Annual costs 2010
tal utility costs $ .1,305,014 Annual costs 2010
Deemed costs per unit * unit participation. Deemed costs per unit is
tar participantcosts 5 L,oss,7zo l1o"Yt""lr:rsllrcel inctuflnlfegiolal.rechnical For:mi.Enercv-- Star and analysis of invoices submitted with incentive applications
Developed and maintained by program administrator- PECI.
To Gross Ratio 0.82 Evaluation Home Energy Savings Program, Cadmus 2010
Life utilize measure speclfic life
Total Resource Cost Test (PTRC)
+ Conservation Adder
0.0501 $1,378,383 $3,247,361 $1,868,978 2.356
Total Resource Cost Test (TRC)
No Adder
0.0501 $1,378,383 $2,952,147 $1,573,763 2.142
Utilitv Cost Test (UCT)0.0475 $1 ,305,013 $2,952,147 $1,U7,134 2.262
Rate lmpact Test (RlM)$3,869,975 $2,952,147 ($917,829)0.763
Participant Cost Test (PCT)$901,771 $3,393,363 $2,491,592 3.763
Lifecycle Revenue lmpacts ($/kwh)$0.0001 034536
Discounted Particioant Pavback (ve 6.00
Measure Grouo lnouts and
rg (lncludes CFLs, Fixturcs and Ceiling Fans) Value Source and Notes
kwh/year Savings (at site) ggg,sor lnn"l results 2010 (Gross at site) based on measure level savings' from Energy Star savings calculator 2OO8 and RTF PTR Software 2007
rram Management and Administration costs s 15,991 li::ffiil:"ntage
(based on kWh contribution) of non -incentive
ntives S EO,fgg Annual costs 2010
Utility Costs S +0,fgf Annual costs 2010
participant costs s 90,204 Deemed b:".d:: RTF estimates developed and maintained bv
program administrator - PECI.
To Gross Ratio 0.82 Evaluation Home EnerBy Savings Program, Cadmus 2010
;ure Life (years) 5 conserva.tive global planning estimate that recognizes trend toward- conservative shorter measure lifes.
IRP Decrement Load Shape East Side Residential Lighting
Rocky Mountain Power
Exhibit No. 1 Page 45 of 495
Case No. PAC-E-1+07
Wtness: lGthryn C. Hymas
kwh/yearSavinss(atsite) aoa,ase fn*"ir#ffffijr:;;;tt'",basedonmeasurelevelsavings
program Manasement and Administration costs s 76,270 :lffi:il:"ntage
(based on kwh contribution) of non -incentive
lncentives S 151,920 Annual costs 2010
Total LJtility Costs S 228,190 Annual costs 2010
Totar partici pant costs s 370,723 ot:T".d based on RTF and Energy star esti mates developed and'' -' - maintained by program administrator- PECI.
0.82 Evaluation Home Energy Savings Program, Cadmus 2010
ia Conservative global planning estimate that recognizes trend toward- ' conservative shorter measure lifes.
East Side Residential Whole House
(Clothes Washers, Dishwasher, Water
; Refrigerator) Value Source and Notes
Net To Gross Ratio
Measure Life (Years)
2008 IRP Decrement Load Shape
Shell Measures (lnsulation and Windows) Value Source and Notes
Annual results 2010 (Gross at Site) based on measure level inputs
Gross kWh/Year Savings (at Site) L,787,743 from RTF PTR Software Version 1.0, FY 2@7 (LO/L(2W-
9 / 30/ Zfi)7)+Cool i ng Coeff icient- Research-Gary Smith-2006
Program Management and Administration costs S 383,u6 o":t1t"1Yt"ntage (based on kwh contribution) of non -incentive' costs for 2010.
lncentives S 62L,307 Annual costs 2010
Total Utility Costs S 1,004,483 Annual costs 2010
Totar participant costs s 5g9,694 windows deemed based on RTF. rnsulation is based on application' analysrs.
Net To Gross Ratio
Measure Life (Years)
2m8 IRP Decrement Load Shape
0.82 Evaluation Home Energy Savings Program, Cadmus 2010
,^ Conservative global planning estimate that recognizes trend toward'" conservative shorter measure lifes.
East Side Residential Whole House
HVAC (AC and Heat Pump Equipmen! Tune ups,
Properlnstallations, Ducts€aling) Value Source and Notes
Annual results 2010 (Gross at Site) based on measure level inputs
GrosskWh/YearSavings(atSite) 6,169 fromQuantecEvaluation2006,ResearchfromEnergyTrustofOregon
20o1, and RTF PTR Software Version 1.0 + Research by Gary Smith
ProgramManagementandAdministrationcosts S 1,17s Allocatedpercentage(basedonkwhcontribution)ofnon-incentive' costs for 2010.
lncentives 5 Zq,YS Annual costs 2010
Total LJtility costs s 26,150 Annual costs 2010
lncremental costs for HVAC measures based on Utah cool cash
Total Participant Costs S ag,fOO program. Tune-ups & heat pumps - RTF. Duct sealing - PTCS/RTF.
Developed and maintained by program administrator - PECI.
Net To Gross Ratio 0.82 Evaluation Home Energy Savings Program, Cadmus 2010
Measure Life (years) 14 conservative global planning estimate that recognizes trend toward- conservative shorter measure lifes.
2008 IRP Decrement Load Shape East Side Residential Cooling
*','["*"y,i:['i3:'"x'"J
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Process and Impact Evaluation
Process and impact evaluations were completed during 2010. The Company during 2010
received process and impact evaluations for program years 2006 to 2008. Results of those
evaluations are avai lable at wrwv. paci fi corp. com/e s/d sm/i daho.
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction porfolio. 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 ofevaluation.
E,hib[iiY11"#i?:'"Xr"J
*-.333i,[?;iitiilfr:i
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.
Measure Group Inputs and Assumptions:
Program lnputs - See ya later, refrigeratoro
kWh/YearSavings(atSite) 1,035,567 Annualresults2010(GrossatSite)
Program Management and Administration Costs S f+af6f Annual costs 2010
lncentives S n,W Annual costs 2010
Total l,ftility costs s 165,801 Annual costs 2010
Participant Costs NA There are no participant costs forthis program.
Net To Gross Ratio
Measure Life (Years)
Utilize measure specific savings and Net To Gross
Utilize meosure specific life
Total Resource Cost Test (PTRC) +
Conservation Adder
0.055r $15s,302 $196,93E $41,636 1.268
Total Resource Cost Test (TRC) No
Adder
0.0551 $1ss,302 $179,035 $23,733 Ll53
utiliry cost Test (UCT)0.0589 $16s.801 $179,03s $13.234 1.0E0
Rate Impact Test (RIM)$393,780 $179,035 (s214,746)0.455
Participant Cost Test (PCT)$r3.r4l $2s 1,619 s238.479 1 9.1 48
Lifecycle Revenue Impacts ($/kwh)$0.00007204r7
Discounted Participant Payback (years)0.27
Refrigerators Value Source and Notes
Number of Units 629 Annual results 2010
Evaluation of Utah Refrigerator Reqtcling Progran - Kema - July 3 I,
Gross kWh./Unit 1,149 2007
Gross kWh/Year Savings (at Site) 722,721 Anrnal results 2010 (Gross at Site)
Net To Gross Ratio 0.57 Evaluation of Utah Refrigerator Reqtcling Prograz - Cadmus - 2010
Measure Life (Years) 5 Evaluation of Utah Refrigeraar Recycling Program - Cadmus - 2010
2008 IRP Decrement Load Shape East Side Residential Whole House
Freezers
Number of Units
C:ross kWh,iUnit
Gross kWh/Year Savngs (at Site)
Net To Cross Ratio
Savings XiC
Nunber of Units
Gross kWh,/Unit
kWh/Year Savings (at Site)
Net To Gross Ratio
Measure Life (Years)
2008 IRP Decrenrnt t ad Shape
Measure LiG (Years) 5 Evahntion ofUah Refigerator Rec.vcling Program - Cadmus - 2010
2008 IRP Decrenrnt Load Shape East Side Residential Whole House
Value Source andNotes
159 Annual resuhs 2010
1,590 Evaluation ofUtah Refrigerator Recycling Progran - Kena - July 31,2007
252,825 Annualresults 2010(Crross at Site)
0.50 Evaluation ofUtah Relrigerator Recycling Prograz - Cadmus - 2010
Value Source andNotes
741 Annual results 2010
81 Evaluation of Utah Refngerator Recyclrng Program - Kema - July 3 l, 2007
60,021 Annual resuhs 2010 (Crross ar Site)
0.63 Evaluation ofUtah Reliigerator Recycling Prograz - Cadnnrs - 2010
6.6 Evaluation ofUtah Refrigerator Recycling Prograr - Cadners - 2010.
F,st Side ResidentralWhole House
Rocky Mountain Power
Exhibit No. 1 Page 48 of 495
Case No. PAC-E-"|4-07
Wtness: Kathryn C. Hymas
Process and Impact Evaluation
Process and impact evaluations were completed during 2010. The Company during 2010
received process and impact evaluations for program years 2006 to 2008. Results of those
evaluations are available at wwr,l'. paci fi corp. com/es/dsnr/i daho
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction portfolio. 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 ofevaluation.
10
Roclq Mountain Power
Exhibit No. 1 Page 49 of 495
Case No. PAC-E-I+o7
\Mtness: Kathryn C. Hymas
Low Income Weatherization - Schedule 21
The following tables outline the primary inputs and assumptions utilized in the cost effectiveness
calculations for the program.
Total ResourceCost Test (PTRC) +
Conservation Adder
0.1330 $133,672 $97,585 ($36,087)0.730
Total Resource Cost Test fiRC) No Adder 0.1 330 $133,672 $88,714 ($44,958)0.664
Utilitv Cost Test (UCT)0.1 330 $133,672 $88,714 ($44,958)0.6&t
Rate lmoact Test RIM)$230,317 $88,714 ($141,603)0.385
Participant Cost Test (PCT)$0 $96,645 $96,645 NA
Lifecycle Revenue lmpacts ($/kwh)$0.00001 51 278
Discounted Particioant Pavback (vears)NA
Process and Impact Evaluation
A process and impact evaluations was initiated during 2010 for program years 2007 - 2009.
Results of those evaluations are expected to be complete in the second quarter of 20 I I .
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction portfolio. 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 ofevaluation.
Program Inputs - I.ow Income Weathization
kWh/Year Savings (at Site) 7lJul6 Annual results 2010 (C-rross at Site)
Program Management and A&ninistratbn Costs $ 124,076 Annual costs 2010
Utilfry A&nin $ 9,596 Annual costs 2010
btal Utility Costs $ 133,672 Annual costs 2010
btal Participant Costs NA There are no partbipant costs for this fogam
Net To Gross Ratio 1.00 l,ow income support. NTG assuned to be 1.0
Lire (years) ,r lffiHff ?,Hfl*i;#::Tffii?i"'#*iffii*,-*,
IRP Decrement Load Shaoe East Side Residential Whole House
11
Roclry Mountain Power
Exhibit No. 1 Page 50 of495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Energy FinAnswer - Schedule 125
The following tables outline the primary inputs and assumptions utilized in the cost effectiveness
calculations for the program.
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 party 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
Process and impact evaluations were completed dwing 2010. The Company during 2010
received a process and impact evaluation for program year 2008. Results of the evaluation are
available at u,rnv. pac i fi cclrp. com/es/d sm/i d aho
Program lnputs - Energry FinAnswer
kWh/Year Savings (at Site) t,475,439 Annual results 2010 (Gross at Site)
tramManaBementandAdministrationcosts S 261.588 Annualcosts2010
ntives S 107,598 Annual costs 2010
btal Utility Costs S 369,186 Annual costs 2010
btal Participant Costs 5 ZZq,SZA lncremental costs incurred by consumers based on receipts provided.
ToGrossRatio 0.75 EvaluationofEnergyFinAnswerProgram-Cadmus-2010
Life (Years) 15 Evaluation of FinAnswer Express - Cadmus - 2010
IRP Decrement Load Shape EastSide
Total Resource Cost Test (PTRC) +
Conservation Adder
0.0410 s429.842 $1,033.924 $604,082 2.405
Total Resource Cost Test (TRC) No
Adder
0.0410 $429,842 $939,931 $510,089 2.r87
Utility Cost Test (UCT)0.03s2 s369. I 86 $939.931 $570,745 2.s46
Rate Impact Test (RIM)$955.008 $939.93 I ($1s,077)0.984
Participant Cost Test (PCT)$ 168,254 $693,420 $52s. l 67 4.121
Lifecycle Revenue Impacts ($/kWh)s0.00000083 l4
Discounted Participant Payback (years)3.36
12
.,,'''[ff i:ffil:'T;J
Case No. PAGE-1+07
ess: Kathryn C. Hymas
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction portfolio. 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.
13
Rocky Mountain Power
Exhibii No. 1 Page 52 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
FinAnswer Express - Schedule 115
The following tables outline the primary inputs and assumptions utilized in the cost effectiveness
calculations for the program.
Program lnputs - FinAnswer Express
kWh/Year Savings (at Site) 3,534,752 Annual results 2010 (Gross at Site)
Program Management and Administration Costs 5 327,391 Annual costs 2010
lncentives S 293,098 Annual costs 2010
Totalutilitycosts S 620,489 Annualcosts2olo
Actual customer costs incurred based on project close-out
Total Participant Costs S 906,018 documentation (invoices) - less any adjustments (if necessary) for
baseline equipment.
Net To Gross Ratio 0.76 Evaluotion oJ FinAnswer Express Progrom - Cadmus - 2010
Measure Life L2 Evoluotion of FinAnswer ExDress Proarom - Cadmus - 2010
Total Resource Cost Test (PTRC) +
Conservation Adder
0.0431 $1,01s,988 s2,222,66r sl,206,673 2.1 88
Total Resource Cost Test (TRC) No
Adder
0.0431 $ r,015,988 $2,020,601 $1,004,613 1.989
Utility Cost Test (UCT)0.0264 $620,490 $2,020,601 $1,400,1l I 3.256
Rate Impact Test (RIM)$2,344,001 $2,020,601 ($323,400)0.862
Participant Cost Test (PCT)$688,s96 $2,0 r 6,609 $ 1.328,0r 2 2.929
Lifecycle Revenue Impacts ($lkWh)$0.0000855886
Discounted Participant Payback (years)4.04
14
Rocky Mountain Power
Exhibit No. 1 Page 53 of495
Case No. PAC-E-1zl-07
Vvitness: Kathryn C. Hymas
Measure Group Inputs and Assumptions:
Lighting Value Source and Notes
kwh/Year Savings (at Site) 1,747,ffi Annual results 2010 (Gross at Site)
" Allocated percentage (based on kWh contribution) of non -incentiveProgramManagementandAdministrationCosts S 106,291 .or,riorrOiO-
lncentives S 124585 Annual costs 2010
Total utility Costs S 230,875 Annual costs 2010
Retrofit lighting costs are based on actual customer costs. New
Total ParticipantCosts 5 463,358 constructionlightingcostsaredeemedbasedonacombinationof
vendor surveys and third party data.
Net To Gross Ratio 0.76 Evoluation of FinAnswer Express Progrom - Cadmus - 2010
Measure Life (Years) L2 Evoluotion of FinAnswer Express Progrom - Cadmus - 2010
2008 IRP Decrement Load Shape East Side Commercial Lighting
Non-Lighting Value Source and Notes
Gross kWh/YearSavings (atSite) 2,387,152 Annual results 2010(Gross atSite)
program Management and Administration costs s 22r,r@ o":t1tt1f:"ntage (based on kwh contribution) of non -incentive' costs for 2010.
lncentives S 168,514 Annual costs 2010
Total Utility Costs S 389,613 Annual costs 2010
Measures receiving custom incentives are actual costs. lt/lotors and
Total Participant Costs S UZ,S$ HVAC are deemed costs from a combination of vendors and third
party data. - verify with Nexant.
To Gross Ratio 0.76 Evoluotion of FinAnswer Express Progrom - Cadmus - 2010
Measure Life (Years) L2 Evoluotion of FinAnswer Express Progrom - Cadmus - 2010
2008 IRP Decrement Load Shape East Side System
Cost Effectiveness Inputs at the Measure Level:
The savings estimates from a third party administrator are the basis for several savings
calculations tools used to manage the Idaho FinAnswer Express program. Savings from lighting
is calculated through an Excel based tool built and maintained by the program staff that includes
deemed wattages by fixture types for both baseline alld 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 efficiency measures are calculated in a manner
similar to motors.
15
Rocky Mountain Power
Exhibit No. 1 Page il of 495
Case No. PAC-E-14-07
Vllrtness: Ka0rryn C. Hymas
Cost effectiveness inputs included in this section are the ag$egations of savings and
expenditures in two large categories - lighting and nonJighting.
Process and Impact Evaluation
Process and impact evaluations were completed during 2010. The Company during 2010
received process and impact evaluations for program years 2006 to 2008. Results of those
evaluations are available at wrr,w. pacificorp. corn/e s/d sm/idaho
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction portfolio. 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 ofevaluation.
16
Rocky Mountain Power
Exhibit No. 1 Page 55 of495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
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.
Energ;y Services (lrrigation Energy Savers)
kWh/Year Savings (at Site) 2,5L5,t69 Annual results 2o10 (Gross at Site)
ManagementandAdministrationCosts S 386,085 Annualcosts2010
tives 5 zg,gzq Annual costs 2010
ttilitycosts S OSz,009 Annualcosts2olo
Totarparticipantcosts s s61,830 combinationofdeemedandactualcostsdependingonthemeasure
type.
NetTo Gross Ratio 0.74 Evaluation of lrrigation EnergySavers Program, Cadmus 2010
Measure Life At program level, it is a weighted average of the measure group
i nputs.
Total Resource Cost Test (PTRC) +
Conservation Adder
0.0825 $796,222 $933,430 $137,208 1.172
Total Resource Cost Test (TRC) No Adder 0.0825 $796,222 $M8,573 $52,351 1.066
Utilitv Cost Test (UCT)0.0660 $637,010 $848,573 $211,563 1.332
Rate lmoact Test (RlM)$1,129,637 $848,573 ($281,064)0.75't
Particioant Cost Test (PCT)$410,136 $743,551 $333,415 1 .813
Lifecvcle Revenue lmoacts (S/kWh)$0.0001 243095
Discounted Particioant Pavback (vears)4.62
Equipment Exchange and Pivot/linear Upgrades Value Source and Notes
GrosskWh/Yearsavings(atSite) 1,65q488 Annualresults2010(GrossatSite)
program Management and Administration costs s 254,5s3 o":*.'"1f:"ntage (based on kwh contribution) of non -incentive' costs for 2010.
lncentives 5 L46,77O Annual costs 2010
Total Ljtilitycosts S 401,353 Annual costs 2010
Total participant costs s 273,699 t:t.bt.":tt:" of d3emed measure costs based on program
" -'--- administrator and actual customer costs submitted with applications
Net To Gross Ratio
Measure Life (Years)
2@8 IRP Decrement Load Shape
0.74 Evaluation of lrrigation Energy Savers Program, Cadmus 2010
5 Evaluation of lrrigation Energy Savers Program, Cadmus 2010
East Side Commercial Cooling
17
Roclq Mountain Power
Exhibit No. 1 Page 55 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
ro8ram Management and Administration costs s rsr,sos lffliffi:tntage
(based on kwh contribution) of non -incentive
ntives S 104,154 Annual costs 2010
n Upgrades Value Source and Notes
kWh/Year Savings (at Site) 85Q581 Annual results 2010 (Gross at Site)
rl utility costs S 235,657 Annual costs 2010
Actual customer costs incurred based on project close-out
rl Participant Costs S 288,131 documentation (invoices) - less any adjustments (if necessary) for
baseline equipment.
To Gross Ratio 0.74 Evaluation of lrrigation Energy Savers Program, Cadmus 2010
;ure Life (Years) 7 Evaluation of lrrigation Energy Savers Program, Cadmus 2010
IRP Decrement Load Shape East Side Commercial Cooling
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 Irrigation 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
utilizing program funded engineering.
The Company ag$egates savings and incentives for reporting at the program level.
Cost effectiveness inputs included in this section are the ag$egations 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 $oupings are utilized to reflect similar measure lives.
Process and Impact Evaluation
Process and impact evaluations were completed during 2010. The Company during 2010
received process and impact evaluations for prograrn years 2006 to 2008. Results of those
evaluations are avai labl e at r.l"r'1u,. pac i fl corp. c orn ie s/d srni i daho
In the future, the Company intends to complete process and impact evaluations on a two year
cycle for each program in the energy efficiency and peak reduction portfolio. 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 ofevaluation.
site
18
Rocky Mountain Power
Exhibit No. 1 Page 57 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
vRocKYMOUNTATN-<POWER
\ A DTVTSTON OF PACTFTCORP
Appendix2
ScheduleT2 &72A
ldaho lrrigation Load Control Programs
2010 ldaho lrrigation Load Control Quantitative Review
7 January 2011
Rocky Mountain Power
Exhibit No. 1 Page 58 of495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Table of Contents
Page
2010 Schedule 72 (Scheduled Forward) Results .........,.........,..,,....,1
Table One Longitudinal and Current Year Scheduled 72 Eligible & Full-Year Participating Sites & Customers.... 1
Table Two 2010 Schedule 72 Participation Credits by Month ............. ...................2
Table Three Longitudinal and Cunent Year Scheduled 72 Participation Credits lssued ........................................ 2
Table Four Comparative Scheduled 72&724 (Total) Costs 2003, 2004 & 2005..,......... ...............2
Table Five Schedule 72 Program Nominal Loads by Participation Option............. .........................3
Table Six Schedule 722010 Nominal kW by Month, Monday Control Day & Hour.....,...... ...........4
Table Seven Schedule 722010 Nominal kW by Month, Tuesday Control Day & H0ur...........................,............, 4
Table Eight Schedule 722010 Nominal kW by Month, Wednesday Conkol Day & H0ur...................................... 5
Table Nine Schedule 722010 Nominal kW by Month, Thursday Control Day & Hour .......................................... 5
Table Ten 2010 Benefit / Cost Categories & Values-Schedule 72 .........,..............6
Table Eleven 2010 Cost-effectiveness Analyses-Schedule 72.......... ....................7
Measurement & Verification (M&V) processes................. ...............7
Table Twelve Schedule 10 Eligible & Full-Year Participating Sites & Cust0mers............,,.... .........8
Table Thirteen Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch Event........................ I
Table Fourteen 2010 Dispatch Dates & Durations,....... ..................9
lllustration One Stair-Stepping Big Grassy Distribution Substation .......,........... 'l'l
Grid-ops tap change dispatches ........................11
lllustration Seven lmpacts of Grid Operations Dispatch Events............. .............12
Table Fifteen Dispatch Program Only: SCADA Estimated Load (kW) lmpacts x Dispatch Event x Designated
Northem Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby).............................. 14
Table Sixteen Dispatch Program Realized Net Load: SCADA Estimated Derived (kW) lmpacts x Dispatch Event
x Designated Northem Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby......... 15
Table Seventeen: Dispatch Program lmpacts less NominalOpt-0u1s......... ........'16
Table Eighteen: Net Load Estimated lmpacts to the Grid in Northern Tier Areas....... ................. 16
Table Nineteen: Total Dispatchable Program (grossed-up) Estimated lmpacts x Hour x Dispatch Event........... 17
Cost-effectiveness analyses
Table Twenty 2010 Benefit / Cost Categories & Values-Schedule 72A .............. 18
Table Twenty-One 2010 Cost-effectiveness Analyses.. ....,...........18
2010 Schedule 72 & Schedule 72A Results ............19
Table Twenty-Two Program lmpacts by Participation Opti0n............. .................. 19
lllustration Eight Dispatch Windows for Dispatch Event Scheduled Blocks & Asset Management Dispatches....20
Table Twenty-Three Hourly Estimated Load lmpacts Entire 2010 Program Season........... .........21
Load profile data impact analysis
Table Twenty-Four 2010 Benefit / Cost Categories & Values-Schedules 72 &72A......... ........,..27
Table Twenty-Five 2010 Cost-effectiveness Analyses.. ..............,.28
Roclq Mountain Power
Exhibit No. 1 Page 59 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Grid characteristics and associated distribution of program loads............. ..........................28
Grower perception considerations...............,.,,.. ...............,........ 28
Attachment One: Rocky Mountain Power Northern Tier Transmission Substations..................,..,,...,...,.......,.31
Geo-spatial location of transmission substations.................. ................3'l
Rocky Mountain Power
Exhibit No. 1 Page 60 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Report Organization
ldaho 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 ldaho lnigation Load
Control Program (Program). ln 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 efficacy of a 2-way control
technology. This report presents quantitative results on Schedule 72 and Schedule 72A as required by the
Commission order. The Schedule 72A assessment will follow the standard report. Summary statistics from both
Schedule 72 and Schedule 72A will be combined and presented. Recommendations and Conclusions will be
presented, All costs are accrued for the 2010 program year ('l October 2009 through 31 September 2010) with the
exception of participation credits.
Unless otherwise noted, data are calculated as of 19 October 2010. lt should be further noted that in previous years
report analysis was done on nominal (book) values of participating loads. ln 2010 and primarily for Dispatch results
we reflect avoided load data based on SCADA analysis of avoided loads.
Background
Reporting requirements include responses to the following:
1. The number of inigation customers who were eligible to participate in the Program
2. The number of inigation customers who entered into a load control Service Agreement
3. The number of inigation customers who participated in the Program for the full three and one-half months
4. The number of inigation 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 and/or recommendations to improve the Program
2010 Schedule 72 (Scheduled Forward) Results
Table One
Longitudinal and Current Year Scheduled 72 Eligible & Full-Year Participating Sites & Customers
Participant Sites Particioant Customers
2003 Actual Participants
2004 Actual Participants
2005 Actual Participants
2006 Actual Participants
2007 Actual Participants
2008 Actual Participants
2009 Actual Participants
201 0 Actual Participants
Eligible 2010 Counts
Customers N0T eligible to participate 2010
401
734
1,065
931
681
87
123
122
207
340
489
478
405
79
112
105
2010 ldaho lnigation Load Control Program-Final Report
4,701 1,975
Page 1
Rocky Mountain Power
Exhibit No. 1 Page 61 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Table Two
2010 Schedule 72 Participation Credits by Month
June July August
Standard Credits $11,686.82 $15,491.89 $14,630.13
kW Under Contract 3,950.51 4,466.0 4,332.0
TotalCredits $41,808.84
Note: avoided kW is as ofthe day of credit issuance
Table Three
Longitudinal and Current Year Scheduled 72 Participation Credits lssued
Total Participation Credits lssued
2003 $277,583.72
2004 $410,325.49
2005 $M2,666.80
2006 $925,577.33
2007 $684,924.98
2008 $30,680.65
2009 v3,912,27
2010 $41,808.84
Table Four
Comparative Scheduled 72 &72A (Total) Costs 2003, 2004 & 2005
2003 Costs 2004 Costs 2005 Costs
Cost Catesory (April '03-Sept'03) Oct'O3-Sept'04 Oct'04-Sept'05
Administrative support $9,613.43 $1 ,665.29 $851 .56
Proqram evaluation $2,135.43 $8,369.88 $1,820,00
Field / Equip / Db admin, expenses $250,222.98 $239,807.03 $326,061.01
Participation credits $277,583.72 $410,325.49 $842,666.80
Proqram manaqement $10,992.99 $55,036.29 $54,826.69
Reporting $351.79 $1,940.00 $0.00
TotalProqram costs $550,900.34 $717,143.98 $1,226,226.06
Note: 2003 osts over 6 monh period; subsequent Program-year cosb are calculated over a 12 monh period (1 October hru 31
September)
1 Throughout this report and in all cases avoid demand nominal values are reported at he site and are NOT grossed-up by 10.39% for generation
thereby taking into account T&D losses.
2010 ldaho lnigation Load Control Program-Final Report Page2
Rocky Mountain Power
Exhibit No. 1 Page 62 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Table Four (cont)
Comparative Load Control Program (Total) Costs 2006, 2007 & 2008
Cost Category
2006 Costs
Oct'05-Sept'06
2007 Costs 2008 Costs
Oct'O5-Sept'06 Oct'O7-Sept'08
Administrative support $194.60 $1,500.00 $1,640.50
Proqram evaluation $1,125.00 $2,268.75 $2,268.75
Field / Equip / Db admin. expenses $330,802.05 $747,664.85 $2,816,386.26
Participation credits $925,577.33 $1,752,930,47 $5,993,868.57
Program management M2,554.85 $80,144.00 $94,051.68
Reportinq $0.00 $0.00 $0.00
Total Proqram costs $1,300,253.83 $2,s84,508.07 $8,908,215.76
Table Four (cont)
Comparative Load Control Program (Total) Costs 2009 & 2010
2009 Costs
Cost Category Oct 08-Sept'09
201 0 Costs
Oct '09-Sept '010
Administrative support $253.27 $0.0
Proqram evaluation $4,195.00 $1 1,758
Field / Equip / Db admin. expenses $3,361 ,818.68 $3,801,022.87
Participation credits $7,246,582.84 $8,101,480.75
Proqram management $67,760.75 $1 17,518.03
Reporting $0.0
TotalProqramcosts $10,680,610.54 $12,031,779.65
Table Five
Schedule T2Program Nominal Loads by Participation Option
Participation Option
Site June July Avoided Aug. AvoidedCnt. Avoided kW kW kW
Optionlmw2-8 1,713.5 1,797.5 2,019.0
Option lt th 2{910.0 1,012.5 992.0
Optionll mw3-6 10 293.5 393.5 298.5
Optionll mw4-7
Option ll t th 3-6
Ootion ll t th 4-7 19.0
Optionlllmtwth3-6 u4.5 376.0 316.5
optionlllmtwth4-7 31.0 31.0 30.0
Option lV m 2{2U.5 384.0 290.5
Option lV w 2{
Schedule Fonrvard Totals
2010 ldaho lnigation Load Control Program-Final Report
122 3,760 4,289 4,241
Page 3
JUNE Mondav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1,978.0 2,616.0 2,647.0 2,647.0 2,009.0 1,978.0
Rocky Mountain Power
Exhibit No. 1 Page 63 of 495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
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, conhol day (Monday-Thursday) and hour.
Table Six
Schedule 722010 Nominal kW by Month, Monday Control Day & Hour
Table Seven
Schedule 722010 Nominal kW by Month, Tuesday Control Day & Hour
JULY Mondav Avoided kW bv Hour
Hour 2:00-2.59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,181.5 2,951.0 2,982.0 2.982.0 2.212.5 2.181.5
AUGUST Mondav Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,309.5 2.924.5 2,954.5 2,954.5 2,339,5 2,309.5
JUNE Tuesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 910.0 1254.5 1305.5 1305.5 961,0 910.0
JULY Tuesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1 ,012.5 1,388.5 1,440.0 1,440.0 1,064.0 1,012.5
AUGUST Tuesdav Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00{:59 7:00-7:59
Avoided kW 992.0 1.308 s 1,357.5 '1,357.5 1,041.0 992,0
2010 ldaho lnigation Load Control Program-Final Report Page 4
JUNE Wednesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1.896.0 2,534.0 2.565.0 2.565.0 1.927.0 1.896.0
Rocky Mountain Power
Exhibit No. 1 Page A4 of 495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Table Eight
Schedule 72 2010 Nominal kW by Month, Wednesday Control Day & Hour
Table Nine
Schedule 72 2010 Nominal kW by Month, Thursday Control Day & Hour
JULY Wednesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2.071.0 2.840.5 2,871.5 2,871.5 2.102.0 2,071.0
AUGUST Wednesdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,294.0 2,909.0 2,939.0 2,939.0 2,324.0 2.294.0
JUNE Thursday Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 910.0 1.2U.5 1.305.5 1.305.5 s6'1.0 910.0
JULY Thursdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1 ,012.5 1.388.5 1.440.0 1.440.0 1.064.0 1 ,012.5
AUGUST Thursdav Avoided kW bv Hour
Hour 2:00-2:59 3:00-3:59 4:004:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 992.0 1.308.5 1.357.5 1,357.5 1 ,041.0 992.0
2010 ldaho lnigation Load Control Program-Final Report Page 5
Rocky Mountain Power
Exhibit No. 1 Page 65 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Cosreffectiveness analyses
Cost-effectiveness is calculated for the following program components:
1. Schedule 72 (Scheduled Foruard)only
2. Schedule 72A (Dispatch) only
3. Schedule 72 and Schedule 72A (combined)
Results on each of the four standard utility industry tests-(1) Total Resource Cost (TRC); (2) Utility; (3)
Ratepayer and (4) Participant will be provided for each of the three aforementioned program cases. The tests
for Schedule 72 (Scheduled Forward option) will be based upon the cost and nominal MW values as defined
in Table Ten belowz. The information below will 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 vanous
benefiUcost testsr. The benefits (avoided costs) are based on the calculations as defined by the Company's
lntegrated Resource Planning (lRP) organization and presented to the ldaho Public Utilities Commission,
and the ldaho lnigation Pumpers'Association in a report titled Proposed Valuation Methodology for the ldaho
lrrigation Load Control Program. lt should be noted that the avoided costs used in all cost-effectiveness
analyses calculations presented in this report considered the overall program size (Scheduled Fonrvard +
Dispatch program options) rather than individual program charactenstics. 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
201 0 Benefit / Cost Categories & Values-Schedule 72
Cost Cost Values Beneflt Benefit Value
$/kW-yr avoided $73.0g/kwAdministrative support
Program evaluation
Field / Equip / Db admin. expenses
Participation credits
Program management
$0.0
$175.46
$56,722.69
$41,808.84
$1,753.72
Total $100160-22
Note: wih the exception of participation credib costs have been allocated based on the percent of load the
Schedule Fomard option comprises of he total (combined) inigation load control programs.
Costs used in these calculations include adminiskative costs, contractor costs (field technician, customer
service, equipment and back office system design / adminishation) and associated participant credits costs.
2 To the extent possible, certain cost categories have been allocated by (1 ) the respective Schedule initiative and (2) percent of participating load.
3 Note hat no discounting of costs or benefits was required in this analysis since all costs and benefits occurred in program year 2010.
2010 ldaho lrrigation Load Control Program-Final Report Page 6
Roclry Mountain Power
Exhibit No. I Page 66 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
The participation credits are not included in the Total Resource Cost (TRC) test because they are a transfer
payment from the utility to the participants.
The cosheffectiveness of the Program was calculated by Cadmus using a simplified spreadsheet analysis.
This analysis multiplies nominal 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 $73.091kW-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 cosheffectiveness calculations.
Based on previous research that showed energy use is'shifted'ratherthan '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 Utility 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 Tabte Eleven.
Table Eleven
201 0 Cost-effectiveness Analyses-Schedule 72
Benefits Costs Net Benefits BenefiUCost Ratio
TRC $147.il2.97 $58,651.87 $88,891.10 2.52
Utility $147,il2.97 $100,460.71 $47 ,082.26 1.47
Ratepayer $147,542.97 $100,460.71 $47,082.26 1.47
Participant $41,808.84 $41,808.84 N/A
Measurement & Verification (M&V) processes
The control equipment provides log files that can authoritatively determine issues of grower fraud andior
tampering with the control equipment. Throughout the 2010 season there remained a residual amount of
confusion among growers relative to equipment / program operations. Accordingly, the lrrigation
Management Team decided that it would be important to provide additional M&V field technician site visits.
This was done to meet customer services as well as M&V objectives. ln the end there were no sites reported
to be out of compliance relative to grower fraud. There was, throughout each of the site visits, significant
attention to training and easing grower fears i concems regarding the remote control equipment and how
best to operate the equipment relative to agri-operation requirements.
Test
20l0 ldaho lnigation Load Control Program-Final Report P4e7
Rocky Mountain Power
Exhibit No. 1 Page 67 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
2010 Schedule 72A (Dispatch) Results
Table Twelve
Schedule 10 Eligible & Full-Year Participating Sites & Customers
2008 Actual Participants
2009 Actual Participants
201 0 Actual Participants
Eligible 20'10 Counts
Customers NOT eligible to participate 2010
ParticipantSites ParticipantCustomers
1,491 530
1,927 826
2,194 773
4,701 1,975
Note: 'customers' is a calotlated number and is based on a query employing he'distincl'operand
Customer Opt-Outs
Schedule 72A permits growers to 'optout' of five Dispatch Events throughout the lrrigation Season. Each of
these opt-out events incurred a cost resulting in a reduction to the custome/s Load Control Service Credit.
The cost to optout is the day-ahead ($/MWh) RMP would otherwise have to pay for power during that
dispatch period. A summary of ophouts, liquidated damages and kW not avoided by each of the Dispatch
Events is presented in Table Thirteen. Table Fourteen summarizes 2010 dispatch dates and durations.
Table Thirteen
Opt-outs, Liquidated Damages, kW4 NOT Avoided and $/MWh by Dispatch Event
Counl
Dispatch
Date
Count of Sites
Weekdav Ootino-outs
Liquidated kW NOT $/MWhDamaqes Avoided (dav ahead)
1
2
J
4
E
b
7
8
9
10
11
29-Jun Thursday
8-Jul Thursday
15-Jul Thursday
16-Jul Friday
19-Jul Monday
20-Jul Tuesday
26-Jul Monday
2-Aug Monday
S-Aug Thursday
24-Aug Thursday
26-Aug Thursday
totals / average ($/MWh)
$856.05 4,553.5
$1,040.61 5,946.0
$4,124.64 19,830,0
$3,587.08 15,802.0
$3,920.19 17,269.5
$4,909.27 23,157.0
$2,177 .28 1'1 ,458 5
$986.39 4,81 1.5
$1,502.75 7,551.5
$1,258.80 5,245.0
$697.98 3,116.0
40
45
125
98
90
142
81
JJ
40
25
21
M7.00
$43.75
$52.00
$56.75
$56.75
$53.00
$47.50
$51.25
$49.75
$60.00
$56.00
$25,061.M 118,740.5 $s2.16
a kW represents connected load based on the average monthly demand for June, July and August for 2008 and 2009.
2010 ldaho lnigation Load Control Program-Final Report Page 8
Rocky Mountain Power
Exhibit No. 1 Page 68 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Table Fourteen
2010 Dispatch Dates & Durations
Dispatch Dispatch
Dispatch dates Duration (hours) Dispatch dates Duration (hours)
August
Tuesday, June 29, 2010 4 Monday, August 02, 2010 4
Thursday, August 05, 2010 4
Tuesday, August 24, 2010 4
Thursday, July 08, 2010 4 thursday, August 26, 2010 4
Thursday, July 15,2010 4
Friday, July 16, 20'10 4 Grid-ops dispatch
Monday, July 19, 20'10 4 Tuesday, June 01,2010 1
Tuesday, July 20, 2010 4 Wednesday, June 02,2010 1
Monday, July 26,2010 4 Monday, June 07,2010 1
Wednesday, July 14,2010 4
Grand Total hours 5'l
Dispatch Events
Problem definition
ln 2009 the Customer & Community Management (C&CM) organization along with the lnigation
Management Team leamed that Dispatch Events (DE) could no longer simply be implemented in a single 4-
hour window. The reason for this was as follows:
* The distribution system in southeast ldaho that serves rural, primarily agri-irrigtion areas has very
little / no automation. Accordingly, capacitors are manually engaged each season as inigation load
increases at the beginning ofthe season. The capacitors are disengaged at the end ofthe season
in a similar manner.
.:. Pump load (motors) create inductive line reactance (lagging); line capacitors (capacitance
reactance) are placed on the circuits to counter-act this effect so the sinusoid electrical wave is at
unity or as close to unity as possible thereby maintaining operational efficiency.
+ By the time irrigation load control begins to execute dispatch events all line capacitor banks have
been manually engaged.
t To compensate, the Company would have to physically disengage the capacitor banks in
anticipation of a DE and conespondently reengage the capacitor banks following each event in
order to accommodate the return of the inductive load, an activity that from a resource perspective
is not supportable.
* Moreover, and with the precipitous and instantaneous drop in load, the voltage regulators (which
are in the distribution substation as well as on the distribution circuits themselves) simply do not
have sufficient time to make a'step change' to maintain appropriate voltages. Note: regulators
require -90s to'adjust'to a change in the load.
July
2010 ldaho lnigation Load C0ntrol Program-Final Report Page 9
Roclq Mountain Power
Exhibit No. '1 Page 59 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
* Due to (1) the magnitude of the program's participating loads, (2) the concenhation of loads on
agricultural-dominant substations and (3) circuits not having the capability to scale loads DE events
were inadvertently creating a situation where there is (1) too much capacitor reactance and (2) too
high of voltage (outside of IEEE + tarifi specifications).
To avoid this situation DE's require intelligent scheduling / implementation. ln 20'10 and beyond DE's would
be required to be implemented in such a way that lrrigation Load Control provided a rudimentary'Smart
Grid'. Additionally and anticipated, 'smart implementation' would augment existing infrastructure assets and
perhaps improve Grid performance. A description of the problem solving process and the benefits associated
with the resultant approach are discussed below.
Analysis and solution
To deliver on this objective a 6-month modeling exercise was undertaken. The effort involved professional
resources from Customer & Community Management (C&CM), Grid-Ops, Area Planning, Distribution
Engineering, Metering, and Demand Side Management. The effort began with an inventory of loads for each
of the five transmission substations that provide service to those geo-spatial areas where there is
extraordinary concentration of program participants. ln fact, 77.9% of total program participation (on a load
basis) is served by one of the five transmission substations.
Working with Distribution Engineering (Rexburg Service Center) distribution substations and their associated
circuits were mapped to participating pump / pivot loads. Mapping was completed using the Company's
CADOPS Engineering Database. Coincident with the aforementioned mapping effort the Area Planning
organization for ldaho prepared a 'flicker study'that would model upper and lower limits of loads that could
be removed / added to the circuit in any single 'step' before a power excursion >3% would be generated.
The 3% variation was determined to be the acceptable limit for tariff and IEEE compliance.
Pursuant to the flick study and armed with distribution substation performance parameters, the lnigation
Management Team constructed a step-function load model for each circuit, distribution substation and
transmission substation. Each DE step-function had a 'bounded kW'value for load removal. Specific sites
and the associated grower were identified and 'tagged' by circuit, distribution substation and transmission
substation. Field technicians most familiar with the area served by a transmission substation were asked to
allocate farms / loads in the most appropriate manner to (1) meet target load drops as defined above and (2)
accommodate farming operations.
Field technicians were then tasked to visit each grower together with the appropriate C&CM representative.
The field technician, C&CM representative along with the grower reviewed the specific'dispatch slot'to
determine if the specified 'dispatch slot' would work given their farms, labor, equipment and irrigation delivery
system configurations. Subsequent feedback necessitated changes to the schedule. Altogether 52 separate
dispatches were designed and grower sites slotted into one of the following three 4-hour DE time periods.
.|. 11:00a........,..........3:00p
* 2:00p.....................6:00p
* 3:00p.....................7:00p
2010 ldaho lnigation Load Control Program-Final Report Page 10
Rocky Mountain Power
Exhibit No. 1 Page 70 of495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Once into the dispatch season the lrrigation Management Team learned from Area Planning that the Hamer
Distribution Substation which was originally planned to be fed out of Jefferson Transmission Substation
would, for the 2010 season, continue to be fed out of Big Grassy. After the first four DE's the C&CM
representative along with the lrrigation Management Team was informed that DE's were continuing to over-
volt the Big Grassy transmission sub, Further dispatching would require that still further load be shifted away
from the 11:00a - 7:00p dispatch window. Accordingly, a fourth dispatch window was established that
operated from 7:00a - 11:00a. Approximately 20 MW of load was shifted to the 7:00a - 11:00a dispatch
window. Here as in other aspects of the lrrigation Load Control initiative, growers stepped-up and
volunteered to change their schedule to accommodate the new requirement.
Results
The result of the stair-stepping of load into and out of DE was a remarkable success. The stair-stepping
worked as expected. Distribution Engineering and Area Planning reported no voltage excursions beyond
standard operating parameters. The impact of stair-stepping on the Big Grassy transmission substation is
depicted in lllustration One which comes directly from Company SCADA data on a sample DE day. Nearly
identical results were replicated on each of the DEs across each of the transmission substations.
llluskation One
Stair-Stepping Big Grassy Distribution Substation
Grid-ops tap change dispatches
Grid Operations together with ldaho Area Planning decided in early July that a 2-step tap change would be
required on the Big Grassy transmission substation in order to maintain voltages within tariff specifications.
Grid Ops approached the lrrigation Management Team requesting a 'special' 1-hour dispatch of -20 MW on
the Big Grassy substation. Coinciding with this DE would be a shift in the load that feeds the associated
v
x
,{
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2010 ldaho lrrigation Load Control Program-Final Report Page 1 1
Rocky Mountain Po\ rer
Exhibit No. 1 Page 71 of495
Case No. PAC-E-1+07
Kathryn C. Hymas
distribution subs (Hamer, Camas, Dubois and Sandune). Executing the tap change in this manner would
allow customers to enjoy continuous service without the inconvenience of a planned outage for ALL loads on
the four distribution substation associated with the Big Grassy transmission substation. Plans to implement
this transition were made for 1 July. The 1 July effort failed due to a problem with the phase shifter on the line
to Anaconda. A second attempt was made the following day (2 July) but this attempt also failed as the loads
were out of synch and the tap change could not be negotiated. A third attempt was initiated on 7 July. The 7
July effort was successful and is so illustrated in lllustration Seven along with the 1 July and 2 July failed
attempts,
Grid Operations again contacted the Company's lnigation C&CM and the lnigation Management Team on 14
July. This time Grid-Ops requested what was at first a 3-hour dispatch and later revised for an additional
single hour in response to a five-mile area of line that had been destroyed in a brush fire, The results of these
special Grid-Ops dispatches are depicted in lllustration Seven.
lllustration Seven
lmpacts of Grid Operations Dispatch Events
Ut g|By (gld oF. dbPftlEl
Table Fifteen provides the estimated loads by dispatch hour for each of the DE's in 2010. The use of
estimated data is markedly dlfferent from previous year reporting where only nominal (book) loads were
used. To the extent possible SCADA estimates provide ffre basis for avoided kW. The reader should keep in
mind that the values reported on the five transmission substations rened.77.9o/o of total program
participation. To assess totalprogram participation one would need to'gross-up'the avoided kW values by
dividing the reported kW by 77.9%. This grossing-up of estimates is performed for the data reported in Table
Nineteen.
ESEfrE:9:!9 -dd6diifiN
2010 ldaho lnigation Load Conrol Program-Final Report Page 12
Rocky Mountain Power
Exhibit No. 1 Page 72 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
The loads reflected in Table Fifteen do NOT take into account credits for AMD dispatch sites and their
associated loads. The AMD loads, of course, are not available for dispatch as they were dedicated for the
AMD tdals. Accordingly, the net estimated realized loads for dispatch across each of the five transmission
substations are presented in Table Sixteen.
2010 ldaho lnigation Load Control Program-Final Report Page'13
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Case No. PAC-E-14-07
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Exhibit No. 1 Page 76 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
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Exhibit No. 1 Page 77 of495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
Cost-effectiveness analyses
Cost-effectiveness calculations were prepared for each of the four standard utility industry tests in the
manner consistent with that described above for the Schedule 72 portion of this program. Benefits and costs
for Schedule 72A (Dispatch option) upon which calculations are prepared are presented in Table Twenty
belows.
Again, the cost-effectiveness of the Program was calculated by Cadmus using a simplified spreadsheet
analysis. This analysis multiplies nominal demand reductions for the June, July and August period (as is
consistent with previous program year calculations) less ophout MW's by the estimated value of avoided
demand. ln the case of Schedule 72A, the value of potential 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 ldaho Public Utilities Commission and the ldaho lnigation Pumpers'
Association in a report titled Proposed Valuation Methodology for the ldaho lrrigation Load Control Program.
The 2010 value was determined to be $73.09/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 $8'1.56/kW-yr.
Table Twenty
201 0 Benefit / Cost Categories & Values-Schedule 72A
Cost Cost Values Benefil Benefit Value
$/kW-yr avoided $73.09/kWAdministrative support
Program evaluation
Field / Equip / Db admin. expenses
Participation credits
Program management
Total $1L8522n32
As shown in Table Twenty-One, Schedule 72A passes the TRC, Utility and Ratepayer Tests. The Program also
passes the Participant Test. However, since the participant incurs no costs the benefiUcost ratio would be infinite.
Accordingly for the Participant Test the value is indicated as 'N/A' in the BeneflUCost Ratio column.
Table Twenty-One
201 0 Cost+ffectiveness Analyses
Net Benefits BenefiUCost Ratio
TRC $21.094.596,62 $3,871,647.03 $17.222.%9.59 5.45
Utility $21.094.596,62 S11.852.229.33 $9.242.367.29 1.78
Ratepayer S21.094.096.62 $11.852.229.33 $9,242,367.29 1.78
Participant $7.980.582.30 $0.00 $7,980,582.30 N/A
5 Again, to he extent possible, costs have been allocated by the reEective Schedule initiative
$0.0
$11 ,582.54
$3,744,s00.18
$7,980,582.30
$115,764.31
Test
2010 ldaho lnigation Load Control Program-Final Report Page 18
Rocky Mountain Power
Exhibit No. 1 Page 78 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
2010 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 nominal impacts by participation option for both Schedule 72and72A are presented in Table
Twenty-Two.
Table Twenty-Two
Program lmpacts by Participation Option
0Ption
Optionlmw2-8
Option ltth2{
Optionllmw3-6
Optionllmw4-7
Option ll t th 36
Option ll t th 4-7
Optionlllmtwth3-6
Optionlllmtwth4-7
Option lV m 2-8
Ootion lV w 2-8
Counts
52
20
10
0
0
1
8
1
8
June Avoided kW
1,713.5
910.0
293.5
U
0
20.0
344.5
31.0
264.5
182.5
July Avoided kW
1,797 .5
1,012.5
393,s
U
0
20.5
384,0
273.5
Aug Avoided kW
2,019.0
992.0
298.5
0
0
19.0
316.5
30.0
290.5
275.0
Scheduled Forward totals 122 3,760 4,289 4.241
Ootion dispatch dispatchable 2,194 257,882.0 278,291.5 274.302.0
Grand Totals:2,316 261,U|.5 282.580.0 278.il2.5
llluskation Eight, and with the exception of the Grid-Ops dispatches, depicts the four foundational dispatch
blocks. Also note the specific reference to the 'superon-peak' and 'on-peak' dispatch time honzons.
The potential avoided demand by dispatch hour associated with each of the Dispatch Events is presented in
Table Twenty-Three. The values in this table are additive. That is, they represent the combination of
Scheduled Forward loads plus Dispatch loads and are 'grossed-up' for the entire program6, ln considering
these data a zero (0) occasionally appears. This is due to the fact that the Scheduled Forward initiative
operates Monday thru Thursday inclusive. For instance, when the Dispatch initiative was exercised on Friday
the only avoided demand is that associated with Dispatch loads and none occuned after 7:00 pm on Friday.
s The values remain at'site'and are NOT'grossed-up'for T&D losses.
2010 ldaho lnigation Load Control Program-Final Report Page 19
Rocky Mountain Power
Exhibit No. 1 Page 79 of495
Case No. PAC-E-1+07
W'rhess: Kathryn C. Hymas
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Rocky Mountain Power
Exhibit No. 1 Page 80 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Table Twenty-Three
Hourly Estimated Load lmpacts Entire 2010 Program Season
1-Jun 2Jun
tuesdav wednesdav
3-Jun
thursdav
4-Jun
fridav
2:00-2:59 910.0 1,896.0
3:00-3:59 1.254.5 2,534.0 1,254,5 0.0
4:004:59 1.305.s 2.565.0 1.30s.s
5:00-5:59 na 1,305,5 2,565.0 1,305.5 0.0
6:00-6:59 na 961.0 1,927.0 961.0
7:00-7:59 910.0 1,896.0
0.0910.0
0.0
0.0
0.0910.0
10-Jun 1 l-iun
tuesday wednesday thursday friday
2:00-2:59 1,978.0 910.0 1,896.0 910,0
3:00-3:59 2.616.0 1.2s4.5 1.254.5 0.0
4:004:59 2,U7.0 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 2,il7.0 1,305.5 2,565.0 1,305.5 0.0
6:00-6:59 2,009.0 961.0 1.927.0 961.0
7:00-7:59 1.978.0 910.0 '1.896.0 s10.0
'14-Jun 15-Jun
monday tuesdaY
16-Jun 17-Jun 1 8-Jun
wednesdav hursdav fridav
2:00-2:59 1.978.0 910.0 1.896.0 910.0 0.0
3:00-3:59 2,616.0 1,254.5 2,534,0
4:004:59 2,il7.0 1,305.5 2,565.0
5:00-5:59 2,U7.0 1,305.5 2,565,0 1,305.5
6:00-6:59 2,009.0 961.0 1.927.0 961.0 0.0
7:00-7:59 1.978.0 '1.896.0 910 0 0.0
7-Jun
monday
8-Jun 9-Jun
0.0
2.534.0
0.0
0,01,254.5
0,01,305.5
0.0
910.0
21-Jun 22-Jun
mondav fuesdav
23-Jun
wednesday
24-Jun 25-Jun
thursdav fridav
2:00-2:59 910.0 1.896.0
3:00-3:59 2,616.0 1,254.5 2,534.0 1,254.5
4:004:59 2.t47.0 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 2,U7.0 1,305.s 2,565.0 1,30s.5 nn
6:00-6:59 961.0 1.927.0 961.0
7:00-7:59 1,978.0
1,978.0
0.0
0,02,009.0
910.0
2010 ldaho lnigation Load Control Program-Final Report
910.0 1.896.0 0.0
Page21
Rocky Mountain Power
Exhibit No. 1 Page 81 of495
Case No. PAC-E-14-07
VMtness: Kathryn C. Hymas
Table Twenty-Three (cont.)
Hourly Estimated Load lmpacts Entire 2010 Program Season
28Jun 29Jun 30-Jun 1-Jul
monday hresday wednesdav thursdaY
2Jul
friday
1 1:00-'11:59 0.0 68.325.0 0.0 0.0
12.00-12:59 0.0 68,325.0 0.0 0.0 0.0
1:00-1:59 0.0 68.325.0 0.0 0.0
2:00-2:59 1,978.0 103,897.0 1,896.0 1,012.5 0.0
3:00-3:59 2,616.0 128.880.1 2,534.0 1,388.5 0.0
4:004:59 2.U7.0 128,931.1 2.565.0 1,440,0 0.0
5:00-5:59 2,U7 .0 128.931,1 2,565,0 1,440.0 0.0
6:00-6:59 2.009.0 N2W.1 1.927,0 1,064.0 0.0
7:00-7:59 1,978.0 5,371.9 1,896.0 1,012.5 0.0
0.0
0.0
5-Jul
monday
6-Jul 7-Jul 8-Jul
tuesday wednesday fiursday
9-Jul
friday
1 1:00-1 1:59 0.0 0.0 68.325.0 0.0
12:00-12:59 0.0 0.0 0.0 68,325.0 0.0
1:00-1:59 0.0 0.0 0.0 68,325.0 0.0
2:00-2:59 2,181.s 1,012.5 2,071.0 103,999.s
3:00-3:59 2,951.0 1,388.s 2.840.5 129.014.1 0.0
4:004:59 2.582.0 1,440.0 2.871.5 129,065.6 0.0
5:00-5:59 2.982.0 1.440.0 2.871.5 129.065.6 0.0
6:00-6:59 2.212.s 1.064.0 2.102.0 ut02.1 0.0
7:00-7:59 2,181.5 1,012.5 2,071.0 5,474.4
13-Jul 14-Jul I 5-Jul 1 6-Jul
fridaymonday tuesday wednesday thursday
1 1 :00-'1 1:59 0.0 0.0 0.0 68.325,0 68;325.0
12:00-'12:59 0.0 0.0 68,325.0 68,325.0
1:00-1:59 0.0 0.0 68,325.0 68,325.0
2:00-2:59 2,181.5 1,012.5 2,071.0 103,999.5 't00,254,9
3:00-3:59 2,951.0 2,840.5 129,014.1 130,893.6
4:004:59 2.982.0 1.440.0 2.871.5 129,065.6 130,893.6
5:00-5:59 2,982.0 1,440.0 2,871.5 129,065.6 130,893.6
6:00-6:59 2.212.5 1,08r.0 2.102.0 U.402.1 86,606.0
7:00-7:59 2.'181.5 1.012.5 2.071.0 5.474.4 9937.4
0.0
1 2-Jul
0.0
0.0
1,388.5
2010 ldaho lnigation Load Control Program-Final Report Page22
Rocky Mountain Power
Exhibit No. 1 Page 82 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Table Twenty-Three (cont.)
Hourly Estimated Load lmpacts Entire 2010 Program Season
19-Jul 20-Jul 21-Jul 22-Jul
mondav hresday wednesday thursday
23-Jul
friday
7:00-7:59 18,000.0 18,0m.0 0.0 0.0
8:00-8:59 '18,000.0 18,000.0 0.0 0.0
9:00-9:59 18,000.0 18,000.0 0.0
'10:00-10:59 18,000.0 18,000.0
1 1 :00-1 1:59 43.934.8 13.034.8 0.0
12:00-12:59 43,934.8 43,934.8 0.0
1:00-1:59 43,934.8 43,934.8 0.0 0.0
2:00-2:59 82,568.0 106,495.5 2,071.0 1,012.5
3:00-3:59 128,515.3 152,049.3 2,M0.5 1,388.5
4:004:59 128.546.3 152.100.8 2,871.5 1.440.0
5:00-5:59 128,546.3 152,100.8 2,871.5 '1,440.0
6:00-6:59 84,699.3 108,647.3 ' 2j02$ 1,064.0 0.0
7:00-7:59 9,360.4 31,423.0 2,071.0 1,012.5
27-lul 28-Jul 29-Jul 30-Jul
tuesday wednesdav thursdav fridav
7:00-7:59 18,000.0 0.0 0.0 0.0 0.0
8:00-8:59 18,000.0 0.0 0.0
9:00-9:59 18,000.0 0.0 0.0
10:00-10:59 18.000.0 0.0 0.0 0.0
1 1:00J 1:59 43,934.8 0.0 0.0
12:0012:59 43.934,8 0.0 0.0
1:00-1:59 43,934.8 0.0
2:00-2:59 82.568.0 1.012.5 2.071.0 1.012.s
3:00-3:59 128,515.3 1,388.5 2,U05 1,388.5
4:004:59 128.546.3 1.440.0 2.871.5 1.440.0
5:00-5:59 128,546.3 1,440.0 2,871.5 1,440.0
6:00-6:59 84.699.3 1,08r.0 2,1020 1,064.0 0.0
7:00-7:59 9,360.4 1,012.5 2,071.0 1,012.5
0.0
26-Jul
mondav
201 0 ldaho lnigation Load Control Program-Final Report Page 23
Rocky Mountain Power
Exhibit No. 1 Page 83 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Table Twenty-Three (cont.)
Hourly Estimated Load lmpacts Entire 2010 Program Season
3-Aug 4-Aug 5-Aug
tuesday wednesday $ursdav
7:00-7:59 18,000.0 0.0 18,000.0
18,000.0 0.0 0.0 18.000.0
6-Aug
friday
2-Aug
monday
18.000.0 18.000.0
10:00-10:59 , 18,000.0 0.0 0.0 18.000.0
1 1:00-1 1:59 43.S34.8
12:00-12:59 43,934.8 0.0 0.0
1:00-1:59 43.934.8 Tr.386.7
78,378.7 0.0
1.308.5 2.$9.0 123.873.1 0.0
1,3s7.5 2,939.0 1n,9n.1
128.518.8 1.357.5 2.S39.0 123.922.1 0.0
1,041.0 2,324.0 U.U
7:00-7:59 9,488.4 992.0 2.294.0 5,4s3.9
9-Aug
mondav
10-Aug
tuesdav
11-Aug
wednesdav
12-Aug
thursdav
13-Aug
ftidav
7:00-7:59 0.0
8:00-8:59 0.00.00.0
9:00-9:59 0.00.0
10:0010:59
11:00-11:59 0.0
12:00-12:59 0.0
1:00-1:59 0.0 0.00.0
2:00-2:59 2,309.5 992.0
3:00-3:59 1,308.5 2,909.0 1,308.5
2,954.5 '1.357.5 2.939.0 1.357.5
1,357.5 2,939.0 1,357.5
6:00-6:59 1,04 1.0 2,324.0 1,M1.0
2,309.5 992.0 2.294.0 0.0
2010 ldaho lnigation Load Control Program-Final Reporl Page24
Rocky Mountain Power
Exhibit No. 1 Page 84 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Table Twenty-Three (cont.)
Hourly Estimated Load lmpacts Entire 2010 Program Season
7:00-7:59
16-Aug 17-Aug 18-Aug 19-Aug 20-Aug
monday tuesday wednesdav thursday friday
0.0 0.0 0.0 0.0
8:00-8:59 0.0 0.0 0.0 0.0 0.0
9:00-9:59 0.0 0.0 0.0 0.0
1 0:00-1 0:59 0.0 0.0 0.0
1 1:00-1 1:59 0.0 0.0 0.0
12:00-12:59 0.0 0.0 0.0
1:00-1:59 0.0 0.0 0.0 0.0
2:00-2:59 2.309.5 992.0 2.294,0 0.0
3:00-3:59 2,524.5 1,308.5 2,909.0 1,308,5 0.0
4:004:59 2,954.5 '1,357.5 2,939.0 1,357.5 0.0
5:00-5:59 2,954.5 1,357.5 2,939.0 1,357.5 0.0
6:00-6:59 2,339.5 1,M1.0 2,324,0 1,04 1,0 0.0
7:00-7:59 2,309.5 9S2.0 2,294.0 992.0 0.0
0.0
0.00.0
0.00,0
0.00.0
0.0
992,0
23-Aug
mondav
24-Aug 25-Aug
fuesdav wednesdav
26-Aug
thursdav
27-Aug
fridav
7:00-7:59 0.0 18,000.0 0.0 18,000.0 0.0
8:00-8:59
9:00-9:59
'10:00-10:59
1 1 :00-1 1:59
12:00-12:59
1 :00-'l:59
2:00-2:59
3:00-3:59
4:00-4:59
(.nn_q,q0
6:00-6:59
7:00-7:59
0.0 18.000.0 0.0 '18.000.0 0.0
0.0 18,000.0 0.0
18.000.0 0.0 18.000.0 0.0
0.0 43,934.8 0.0 43,934.8 0.0
0.0 43.S34.8 0.0 43.934.8 0.0
0.0 0.0 43,934.8 0.0
2.30S.5 88.004.3 2.294.0 88.0M.3 0.0
2,924.5 133,498.6 2,909.0 133,498,6 0.0
2.954.5 133.547.6 2.939.0 133.547.6 0.0
2,954.5 133,547.6 2,939.0 133,547,6 0.0
2.339.5 "90-153.6 2.324.0 90.153,6 0.0
2,309.5 2,294.0 992.0
0.0'18,000.0
0.0
43,934.8
0.0992.0
2010 ldaho lrigation Load Control Program-Final Reporl Page 25
Roclly Mountain Porver
Exhibit No. 1 Page 85 of495
Case No. PAC-En+o7
\Mhess: lGthryn C. Hymas
Table Twenty-Three (cont.)
Hourly Estimated Load lmpacts Entire 2010 Program Season
0;0
10:00J0:59 ' ':, 03
I I :00-1 I :59 ::: : r i. i0;0
l2:00-12:59 :trrrt,,,r,, t(r 0
.l:00_1:59 iiiir.ri'i.00:rrl
2:00-2:59 2.3095 S92.0
3:00-3:59 :,:',:,:,,''2i924;5
4:ffi4:59'':'::':2:9645 1,3675
5:00-5:59,.,:r::'trp545 1.357.5
6:ffi6:59 ::':':'::i!;Ililg5::::,' 11.641.6
7:0G7:59 ,2.3095
304u9 314u9
monday tuesday
2010 ldaho ln(;aton Load Conrol Program-Final Reprt Page 26
Roclry Mountain Power
Exhibit No. 1 Page 86 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Load profile data impact analysis
Throughout the control period, Company SCADA data were collected and used in preparing estimated 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 Grassy; (3) Rigby; (4) Bonneville and (5) Jefferson. The impact of load
dispatches is dramatic and unequivocal. The magnitude of the first half of June loads is significantly less than
previous seasons. Further analysis suggests that the maturing of field crops and the 2no cutting for alfalfa hay have a
predictable impact on reducing loads post August 'lst.
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. ln 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 and72A upon which calculations are prepared are presented in
Table Twenty-Four belowz.
Table Twenty-Four
2010 Benefit / Cost Categories & Values-Schedules 72 &72A
Cost Values Benefil Benefit Value
$/kW-yr avoided $7s.09/kwAdministrative support
Program evaluation
Field / Equip / Db admin. expenses
Participation credits
Program management
Total $12.03L771165
All-in $/kW program costss $42.58 TotalkW 282,580.
*Total max nominal load br July
As shown in Table Twenty-Five, the combined initiatives (Schedule 72 + Schedule 72A) pass the TRC, Utility and
Ratepayer Tests. The Program also passes the Participant Test. However, since the participant incurs no costs the
benefiUcost ratio would be infinite. Accordingly and for the Participant Test the value is indicated as 'N/A' in the
BenefiUCost Ratio column.
7 All prognam cosb (boh Scheduled Forward and Dispatch program components) have been induded in this table.
I This is a rudimentary calculation simply performed by dividing all program cosb by tre monthly max (July) avoided demand.
$0.0
$11,758.00
$3,801,022.87
$8,101,480.75
$1 17,518.03
2010 ldaho lnigation Load Confol Program-Final Repon P4e27
Rocky Mountain Power
Exhibit No. 1 Page 87 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Table Twenty-Five
20'l 0 Cost+ffectiveness Analyses
Costs Net Benefits BenefiUCost Ratio
TRC $zr,oss,goo.eo $s,gso,zgg.go $rz,zzg,oor.go s.sr
Utility $21 ,653,300.86 $12,031,779.65 $9,621 ,S21 .2.1 1.80
Ratepayer $21 ,653,300.86 $12,031 ,779.65 $9,62.1 ,521 .21 1.80
Paffcipant $8,101,480.75 $0.00 $8.101,480.75
Conclusions
Grid characteristics and associated distribution of program loads
* Altogether, the load on the five transmission substations monitored comprises -77.9Y0 of the total inigation
load control participating load.
With the exception of the Rigby Transmission Substation there is virtually no load diversity on the four
transmission substations-(1)Amps; (2) Big Grassy; (3) Jefferson and (4) Bonneville.
Of the five transmission substations monitored-((1) Amps; (2) Big Grassy; (3) Jefferson, (4) Rigby and (5)
Bonneville) there is a total of 336 MW. Of that total, irrigation load represents 295MW or 88%.
lnigation Load Control Program participation on the five monitored transmission substations totals to
220MW or 75% of the total available inigation load and 65% of the total load.
66 of the 90 circuits (or 73o/o of the circuits) fed by one of the five transmission substations have inigation
loads that represent >85% of the total load on that circuit
55 of the 90 circuits (or 61% of the circuits) fed by one of the five transmission substations have irrigation
loads that represent >95% of the total load on that circuit
The above data make it more than clear that DE's must absolutely be executed in an intelligent fashion.
Grower perception considerations
* The 20'10 Dispatch stair-stepping 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-irrigation / information systems specialists
and inigation equipment / agriclectrician specialists.
The 2010 season represented the St,consecutive season where no complaints have been issued to either
the Commission or to the Company. Local C & CM staff and field teams have been required and are
motivated to a customer service approach to solving problems coincident to when the problem presents
itself. This approach is viewed and valued as a risk mitigation strategy and ultimately minimizes program
and Company costs.
2010 ldaho lnigation Load Control Program-Final Report Page 28
Rocky Mountain Power
Exhibit No. 1 Page 88 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
* Throughout the 2010 season additional growers began to actively use the remote control equipment for
regular inigation turns. That said, there has been and remains a variety of interesting technical issues and
operational considerations that require additional attentions to ensure system robustness.
The principle issues that blunt further program effectiveness center on equipment reliability and program size, which
impacts program realization during any particular hour needed.
Change considerations
* Growers perceived the stair-stepping of loads into and out-of dispatch events along with minimizing loads
that could be removed at any one time had a positive effect on pump motors.
* The stair-stepping effort was and is the precursor to a 'smart-grid'. Successful further utilization of lrrigation
Load Control to achieve the benefits of 'smart-grid' will require a continued cooperative efforts between
various RMP organizations including but not limited to C & CM, Distribution Engineering, Grid-Ops,
Demand Side Management, Area Planning, Commercial& Trading, Metering and Regulatory. The benefits
of a 'smart-grid' approach require quantification, however.
Meteorological considerations
* From a meteorological perspective the 2010 season was relatively normal both in terms of rainfall and
temperature.
* That said the first two weeks of June were wetter and cooler than normal and it had a particularly adverse
effect on hay production. Moreover, field crops were late in the harvest cycle. Some fields were not
harvested until September.
Recommendations
* Find a solution to the equipment reliability issue, The 2-way equipment has allowed the program to migrate
to a 'dispatch' initiative. That said, making the transition has come at a price. Time, resources and budget
have been consumed with simply getting and keeping the system operational. RMP is and will continue to
work with the equipment vendor to remedy cunent equipment shortcomings and to further 'harden' the
equipment for the harsh agricultural environment.
* Design dispatch protocol to extract additional value from a 'smart-grid' approach. For example, in 2010
benefit from lrrigation Load Control was provided to C&T, Grid-Ops and Area Planning. Concomitant
efforts will be required to appropriate value these benefits and to assess their viability to alternative
solutions.
2010 ldaho lnigation Load Control Program-Final Report Page 29
Rocky Mountain Power
Exhibit No. 1 Page 89 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Continue to work with individual growers and the llPA to gain their support for the variety of requisite
dispatch protocols and potential offerings that could add additional value to the Company and to the ldaho
ratepayer.
To date the Company has constructed a solution that has required creativity and innovation. From the
control technology, to program design and operations a solution has been built from the ground up and at
each juncture the Company has had to evolve the program solution to address new challenges. While
much is behind the lnigation Management Team, continued program evolution is anticipated to resolve
technical problems and maximize the value to the Grid. Accordingly, current tariffs may require
modification to accommodate the flexibility required to allow for the testing of altemative solutions,
operational processes / practices.
2010 ldaho lnigation Load Control Program-Final Report Page 30
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Exhibit No. 1 Page 90 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
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Bfiibit No. 1 Page 91 of 495
Case No. PAC-E-1+o7
W'(ness: Kathryn C. Hymas
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Exhibit No. 1 Page 92 of495
Case No. PAGE-1+07
\nfitness: Kathryn C. Hymas
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Exhibit No. 1 Page 93 of 495
Case No. PAC-E-14-07
\Mtness: Kalhryn C. Hymas
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Exhibit No. 1 Page 101 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Date:
To:
From:
Re:
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CAT}MTJS
March 24,2011
Jeff Bumgarner
Jim Stewart, Hossein Haeri and Brian Hedman
lmpacts of Rocky Mountain Power's ldaho lrrigation Load Control
Program
Rocky Mountain Power retained The Cadmus Group to evaluate the 2009 and 2010 demand
impacts of the company's irrigation load control program offered to the customers in Idaho. This
document summarizes the results of Cadmus's study.
Background
In2009, the Program enrolled 2,032 customers and had approximately 260 MW of participating
load in Schedule 72 (schedule forward) and Schedule 72A (option dispatch). In 2010, the
Program enrolled 1,975 customers and had approximately 283 MW of participating load. In both
years, over 98 percent ofthe Program load was enrolled through the dispatch option.
During the 2008 Program Season the Company began noticing voltage excursions outside
industry acceptable standards during dispatch events. In 2010 the Company implemented a
process to reduce load and return load to normal operating levels in phases to minimize the
impact on the company's transmission and distribution system. As a result, the Company was
still unable to take the entire participating load off during the peak time period between 2:00p
and 6:00p. As a consequence, the current level of participation is beyond what RMP can
effectively dispatch. This has reduced the Program's cost-effectiveness.
Technical Approach
The Cadmus Group estimated the hourly load reductions achieved by the Program in 2009 and
2010. The analysis was conducted using SCADA system data for five sub-stations (Amps, Big
Grassey, Bonneville, Jefferson, and Rigby) that accounted for most (77 percent) of the controlled
irrigation load in Idaho. For each substation and event hour, Cadmus estimated a reference load,
what the load would have been in the absence of the event, and compared it to the observed load
during curtailment events. Results were extrapolated as representative of the remaining circuits
to account fortotal program loads.
The reference load for an event hour was estimated in two ways: (l) as the unconditional average
load in the same hour of the two weekdays preceding and following the event; and (2) as the
conditional ayerage load estimated using a regression of hourly demand on weather. calendar and
time effects, and indicators for event hours and hours preceding and following the event. The
The Cadmus Croup, lnc.
720 SW Washington Street, Suite 400, Portland, OR 97205 r 503.228.2992 r Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24, ?011
Rocky Mountain Power
Exhibit No. 1 Page 102 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Page 2 of 22
diflerence between the observed load and the actual yielded the estimate of the load reduction in
the event hour.
For both estimation approaches, the estimated load reduction in each hour was compared to the
expected load reduction (nominal load reduction) adjusted for opt-outs and a load reduction
realization rate was calculated. There are several aspects of this methodology that are worth
noting before considering the results. Nominal load is defined as the sum of customers' average
billing demands for June, July and August for the two prior years.
o The impact analysis is based on SCADA data at the substation level. Since the majority
of the loads being served by these substations consist of irrigation, the amount of "noise"
in the data resulting from the variability of non-irrigation loads is expected to be minimal.
Moreover, the hourly demand model used to estimate the load impacts largely accounts
for such noise in the substation data.l
Program management staggers (stair-steps) the dispatching of loads at the beginning and
end of events for grid reliability purposes. The hourly analysis of loads does not account
for the staggering. As a result, the estimated load impacts in the first and last hours are
an estimate of the average load reduction over the hour and may not represent the true
reduction at the beginning (likely to be smaller than estimated) or end of the hour (likely
to be larger).
The analysis adjusts for, in the calculation of realization rate, the required scheduling of
22 percent of the available participating loads outside of the 2:00p-6:00p time period.
This scheduling restriction was implemented in 2010 to accommodate the Grid control
voltage limitations previously noted. While this did not impact realization rates, it did
impact the decrease in aggregate reduction from 205 MW in2009 to 156 MW in 2A10.
Results Summary and Conclusions
With these limitations in mind, the evaluation team analyzed the substation data for the 2:00p to
6:00p time horizon and reached the following conclusions:
o In 2009, the maximum hourly load reduction on the five substations was 158 MW which
extrapolates to 205 MW for the entire program. This reduction occurred on July 17 and
represented 86 percent of the nominal load (program resources) adjusted for opt-outs in
the hour. The realization rates, which show how much load was shed relative to
expectation, ranged from a low of 17 percent on August 5 to the July 17 high of 86
percent. In 2010, the maximum hourly load reduction at the five substations was 120
' Of the five substations only the Rigby substation serves other loads, including small businesses, a college, a
hospital and the cities of Rexburg, Rigby, Ririe, Menan, and smaller towns.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 r 503.228.2992 o Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 103 of495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Page 3 of 22
MW which extrapolates to 156 MW for all Idaho irrigation program loads. This occurred
on July 8 and represented 77 percent of the opt-out-adjusted nominal load in the hour.
Program benefits are calculated based on 156 MW of system impact. On July 20, aload
reduction of 120 MW resulted in the maximum realization rate of 82 percent. During
hours when events are traditionally called, realization rates ranged from a low of 29
percent on August 24 to the high of 82 percent on July 20.
o Realization rates were calculated based on expected loads, or in the case of the Rocky
Mountain Program, loads that could safely be dispatched without adversely impacting
line voltages. This is an important distinction worth noting. Had the calculation of
realization rates been based on total participating loads, this would have resulted in lower
realization rates. As program cost-effectiveness is calculated on actual load reductions
relative to a program's costs (rather than a realization rate), realizations rates should not
be considered the definitive measurement of a program's effectiveness and value.
o The load reductions and realization rates in any year may not be representative of typical
load impacts the program might achieve because of annual weather-related variations in
irrigation demand.
o Rocky Mountain Power system peak coincides with hours when events are traditionally
called (hours 2:00p to 6:00p). In 2009, all of the top 10 non-event, summer hours
occurred during the traditional event window. Rocky Mountain Power system peak hours
do not coincide with morning and early afternoon / evening hours when loads were
dispatched in 2010 because of transmission and distribution constraints.
o While the Program has been operationally effective, it has not been as cost-effective as it
could be. In 2009 and 2010, the Program enrolled more load on some substations than it
could dispatch during peak hours because of transmission and distribution constraints.
To increase future cost-effectiveness, RMP needs to either upgrade its transmission and
distribution system in Idaho to remove the operating constraints or limit enrollment in the
Program to a level consistent with the system's ability to dispatch resources during peak
hours.
In addition, since the inception of the program Rocky Mountain Power has been educating
irrigators about efficient irrigation practices and the benefits of irrigating during off-peak
hours. Rocky Mountain Power estimates that because of education irrigators have shifted
between 5 and 7 percent of their loads between 2:00p and 6:00p to offpeak. The estimation
of the reference load for this analysis is not taken into consideration in this analysis. If the
benefits from education were taken into consideration the load shifting from education would
have the effect of fuither improving measured impact or realization rate.
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 104 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Page 4 of 22Jeff Bumgarner
February 24,2011
Objectives
The objectives of this evaluation were:
o To estimate the irrigation load reductions from Rocky Mountain Power's irrigation direct
load control program in 2009 and 2010.
o To estimate ex-post realization rates, the ratio of the ex-post impacts to the nominal program
loads that can be shed.
Program Operations
RMP operates two irrigation load control programs in Idaho. The first is "schedule forward"
(Schedule 72) and involves direct control of irrigation loads on a scheduled basis. Enrollment in
this program has been decreasing annually with the implementation of the dispatch program
option. In July 2009, there were 4.1 MWs of nominal load in this program. The second is the
dispatch option (Schedule 72a). RMP calls "events" wrth 24 hours advance notice and uses
simplex technology to shed irrigation loads during event hours (a maximum of four hours per
day per customer during weekdays).2 The event hours are typically between 2:00p to 6:00p. In
July of 2009, there were 254 MWs of nominal irrigation load in both programs. ln July of 2010,
there were 282 MWs of nominal load.
Event History
In2009, RMP called six events that each lasted four hours. The events occurred between 2:00p
and 6:00p. Table I shows the dates and hours of the events.
Table 1. Event Days and Hours in 2009
30-Jun 4 hours
L7-)ul 4 hours
23-Jul 4 hours
3-Aug 4 hours
5-Aug 4 hours13-Aue 4 hours
Hours for all events occurred
during hours 2:00p to 6:00p.
In 2010, RMP called I I events, excluding three one-hour events in early June and one four-hour
event for irrigators served by the Big Grassey substation and for grid operations purposes.3 ln
addition to a larger number of events in 2010, there were also a larger number of hours when
2 Participants may opt out of a maximum of five events per season.
3 The regression models conffol for the grid operations events, but we do not report the estimated load reductions.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 105 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Page 5 of 22
RMP dispatched program resources. Resources were dispatched during not just 2:00p-6:00p but
also hours before and after this window because of transmission and distribution constraints.
Table 2 shows the dates and number of hours for the 2010 events.
Table 2. Event Days and Hours in 2010
29-Jun 8 hours*SJul 8 hours*
15Jul 8 hours*15-Jul 8 hours*
19Jul 12 hours**
20Jul 12 hours**26-)ul 12 hours**
2-Aug 12 hours**
5-Aug 12 hours**
24-Aug 12 hours**
25-Aue 12 hours**
*Hours for all substations:
11:00a -7:00p.
** For all substations except
Big Grassey, event hours
occurred 11:00a - 7:00p.
Beginning July 19, RMP also
dispatched Big Grassey
customer loads from 7:00a -
11:00a.
Between the first event on lvne29,20l0 and the fourth event on July 16, 2010, RMP dispatched
program resources on event days in three blocks over eight hours: I l:00a -3:00p, 2:00p - 6:00p,
and 3:00p7:00p. Figure I illustrates the dispatch of program resources during these time
blocks.
Figure 1. Summer 2010Irrigation Direct Load Control Dispatch Blocks
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee*Owned Company . www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 106 of495
Case No. PAC-E-14-07
VMtness: Kathryn C. Hymas
Page 6 of 22Jeff Bumgarner
February 24,2011
*rhH,E
DEFN
Beginning with the fifth event on July 19 and ending with the final (llth) event on August 26,
RMP dispatched additional resources between'7 am and 1l am on the Big Grassey substation.a
Resources associated with the other substations continued to be dispatched in three blocks
between I l:00a and 7:00p.
Tables 3 and 4 show loads at the five substations that RMP expected it could shed during each
month of 2009 and 2010 based on the historical demand of enrolled customers. This is known as
the 'nominal' load. The estimates of nominal load in Tables 3 and 4 do not take into account
customers that opted out of events.
In2009, the nominal load varied across months but not hours, as all available program resources
were dispatched during the 2:00p - 6:00p window. Nominal loads were highest during July
when irrigation demand was greatest.
Table 3. Program Nominal Resources (MW) in 2009 for Five Substations
'In addition, there was an AMD dispatch block on Amps 3 days/week from 6:00p -12:00a. This involved a small
amount of load, approximately 1.75 MW per dispatch or 5.3MW in total. All AMD dispatches from all
substations accounted for -15 MW of participating load.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 r 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Program Nominal
lrrigation Load (MW)
served by substations
in estimation sample
Source: Table 14, Schedule 72 and 72A ldaho lrrigation Load
Programs 2009 Credit Rider lnitiative Final Report and personal
communications with Bill Marek about percentage of program
nominal load served by Amps, Big Grassey, Bonneville, Jefferson,
and Rigby substations. Loads are not adjusted for opt-outs.
Nominal load is the load that RMP expected it could shed based
on program enrollment and transmission and distribution
constraints.
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 1 07 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
PageT of ?2
In 2010, the nominal loads on the five substations varied between months and event hour, as
program resources were dispatched in several four-hour blocks, as described above. The nominal
loads do not take into account the gradual ramping down and up of loads at the beginning and
end ofthe period or opt outs.
Table 4. Program Nominal Resources (MW) in 2010 for Five Substations
June 0.0 47.0 47.0 49.0 89.3 148.8 148.8 148.8 110.1 5.8 1.5
July 1-July
19 0.0 50.7 50.7 53.0 96.5 L60.7 150.7 160.7 118.9 6.2 1.8
July 20-
Julv 31 t7.7 42.6 42.6 44.9 88.4 L5L.7 tst.7 L51.7 109.9 6.2 1.8
August 15.9 42.0 42.0 44.2 87.1 L49.6 149.6 149.6 108.3 6.2 !.7
Source: Schedule 72and 72A ldaho lrrigation Load Programs 2010 Credit Rider lnitiative Final Report and
personal communications with Bill Marek. Loads are not adjusted for opt outs. Nominal load is the load that
RMP exoected it could shed based on orosram enrollment and transmission and distribution constraints.
Data
RMP provided Cadmus with 60 second interval data for five substations (Amps, Big Grassey,
Bonneville, Jefferson, Rigby) that served irrigators in its Idaho service territory in 2009 and
2010. The substations accounted for approximately 77 percent of RMP's irrigation load
subscribed in the program in Idaho in 2010. RMP also provided Cadmus with data about the
days and hours when direct load control resources were dispatched.
Cadmus performed a number of quality checks on and adjustments to the interval data before
analyzing the load impacts. We first put the 60 second interval data on an hourly basis by
calculating average hourly loads for each substation. The hourly load data were then plotted and
examined for irregularities. While the minute interval data did exhibit some random spikes and
drops in load (normal perturbations in electrical Grid operations), these abnormalities were not
evident after the minute interval data were averaged over the hour.
Next, we obtained hourly and daily weather data for Rexburg and Idaho Falls weather stations
from the National Weather Service and merged it with the hourly load data. The weather
variables in the analysis include the daily evapotranspiration rate, temperature (hourly), and
rainfall (hourly).s
s The evapotranspiration rate was a weighted average of crop-specific ETRs, with weights equal to the share of land
planted in the crops.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company o www.cadmusgroup.com
Jeff Bumgarner
February 24,2O11
Rocky Mountain Power
Exhibit No. I Page 1 08 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Page 8 of 22
Last, Cadmus mapped information on the occulrence of load control event hours to the data. We
created separate indicator variables for each hour of each event, which were included in the
model.
lmpact Estimation Approach
The Cadmus approach to estimating the load reductions in each event was to estimate a reference
load (what demand would have been in each hour of an event if the event had not occurred) in
each hour during an event window. The difference between the actual load and the reference
load in an event hour is the estimate of the program's impact during that event hour.
Figure 2 illustrates the approach. It shows the hourly loads for the Bonneville substation on July
23, 2009, when RMP called the third event of the summer. The event window was 2:00p to
6:00p. The red (solid) line is the observed load. The blue (dashed) line is the reference load that
was generated with a regression model. The impact of the event in each hour is the difference
between the metered load (red line) and the reference load (blue line). The figure depicts an
estimated average hourly impact of approximately 38 MW.
The reference load can be estimated in several ways. One is a day matching approach. This
involves estimating the (unconditional) average of the loads in the same hour in the two
weekdays immediately preceding and following the event. If irrigation demand conditions,
which are a function of weather, evapotranspiration, crop maturity, and other factors, on the
reference days are similar to those on the event day, the reference load will likely represent well
what demand would have been, and the difference between observed and reference loads will be
an accurate estimate of the true load reduction. However, if any of the demand conditions
change, the load reduction estimates will be biased.
Figure 2. Illustration of Event Impact Estimation Approach
Bonneville: Event 3, July 29
-
Obsenred
load
- - Reference
Load
10 12 14
Hour
16 18 20 22
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company o www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 109 of495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
Page 9 of 22
The second approach is multivariate regression in which loads are modeled as a function of
weather, time, and calendar variables. This method accounts for differences in demand
conditions between event and non-event days and will generate a more accurate reference load.
Cadmus determined that because of trends in irrigation demand over the growing season that the
day matching approach would not be appropriate. Reference loads were estimated using an
hourly demand regression models.
Conditional Demand lmpact Estimation
Using regression analysis, Cadmus also modeled hourly demand as a function of weather (evapo-
transpiration, temperature, and rainfall), calendar and time eflects (week of month, day of the
week, and hour), and load in the same hour in the previous day.6 The models also included
separate indicator variables for each hour of each event and for each of the six hburs following
and preceding each event. The coefficients on the event hour variables represent the differences
between the observed loads and the reference loads in the event hours. The Appendix describes
the model specification in greater detail.
Cadmus estimated separate demand models for each of the substations and event months (June,
July, and August). Thus. there were a total of 15 substation models (5 stations x 3 months). We
estimated separate substation month models for two reasons. First, each substation has a
somewhat different load shape over the summer, reflecting diflerences between stations in
cropping practices and irrigation and non-irrigation demand.T Second. each substation's load
shape varies significantly over the summer, reflecting changes in crop maturity, evapo-
transpiration, soil-type temperature, wind. relative humidity, solar radiation. and rainfall over the
growing season.
Model Estimation and Diagnostics
Cadmus estimated the models by Generalized Least Squares (GLS) under the assumption of
auto-correlated errors, that is, load in each hour is assumed to be correlated with the load during
a preceding hour. The error term was modeled as an autoregressive process with lag one.
We performed a number of tests to evaluate the predictive ability of the substation regression
models. These tests included inspection of the signs and statistical significance of the models'
coefficients, estimation of overall explanatory power of each model, represented bV R' statistic,
6 Loads were modeled as a function of the average temperature in the preceding 24 hours, total rainfall in the
preceding 24 hours, and average daily evapo-transpiration over the preceding three days. The week of month
variables capture changes in irrigation demand related to changes in cropping activities. The days of the week
and hour ofthe day variables capture irrigation dernand that varies by day and hour.
'The Rigby substation is different from the other stations in that it has significant non-irrigation loads.
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Roclq Mountain Power
Exhibit No. 1 Page 110 of495
Case No. PAC-E-14-07
Vvitness: Kathryn C. HymasPagel0of22
and tests of the predictive ability of the models in hours when events could have been called on
non-event days.8 We used the results of the tests in selecting the final model specifrbations.
The models predict accurately what loads would have been in hours when events were not but
could have been called. Table 6 reports the median absolute percentage error, the median of the
percentage difference between the observed load and the load predicted by the model (lkw-
model predicted kw)l/kW, during non-event hours on July weekdays between2 and 6 pm.
Table 6. Median Absolute Percentage Error for July 2009
2:00 PM
3:00 PM
4:00 PM
5:00 PM
0.74% L.45% 7.35% 1.54% 0.72%
0.86% L.44% 1.28% 1.48% 0.67%
L.62% L.29% O.87% 1.280/o 0.64%
o.gs% L.04% 7.09% L.85% 0.57%
Note: Absolute percent error is = lpredicted MW - actual MW l/ actual
MW.
For example, in 50 percent of the 3 pm non-event hours at the Bonneville station, the regression
model predicts a load that is within 1.28 percent of the actual load. The median absolute
prediction error ranges from less than 0.7 percent to just below two percent. Fifty percent
(N:10) of the substation-hour median percentage errors are less 1.2 percent.
Estimated Load Reductions in 2009
Table 7 reports an estimate of the total load reduction for the Amps, Big Grassey, Bonneville,
Jefferson, and Rigby substations and all Idaho irrigation in each event hour during summer
2OO9.e The estimate for Idaho was obtained by dividing the substation estimate by the substation
percentage of the Idaho irrigation load (77 percent). The Table also reports the realization rate
for each event hour (2:00p-6:00p time window). which is the ratio of the estimated total load
reduction in a given hour to the nominal load adjusted for irrigation loads that opted out of the
event.l0 The realization rate is a function of the estimated load reduction (the numerator) and
expectations about loads that can be shed (the denominator). It may be less than or equal to 100
percent depending on technical performance of the control equipment (i.e., signals and
transmitted and received and pumps are shut off) and whether irrigation demand during the
season was less than or greater than expected.
8 [n general, the coefiicients of the models have the expected signs and are statistically significant. Loads were
increasing in the evapo-transpiration rate and temperature and decreasing in rainfall. Loads were generally
highest during the afternoon and early evening hours. Also, based on their R2 statistics. the nrodels explain a
large percentage of the variation in inigation loads.
e The Appendix contains estimates ofthe reduction in load at the substation level in each event hour.
'o Cadmus adjusted the nominal load for an event by subtracting the amount of load that opted out the event.
The Cadmus 6roup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee*Owned Company . www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 111 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. HymasPage11of22Jeff Bumgarner
February 24,2011
Table 7. Estimated Load Reductions and Realization Rates in 2009
30Jun Event 1 Hour 1 -4]-.8 -54,3 24.8%
Hour 2 -77.8 -93.2 42.60/o
Hour 3 -70.7 -91.8 42.0%
Hour 4 -66.4 -86.3 39.5o/o
L7-Jul Event 2 Hour 1 -111.1 -L44.3 60.8%
Hour 2 -157.8 -204.9 86.3%
Hour 3 -158.0 -205.2 86.4%
Hour 4 -151.5 -195.9 829%
23Jul Event 3 Hour 1 -702.4 -133.0 55.7%
Hour 2 -L37.7 -778.9 74.9%
Hour 3 -138.6 -180.0 753%
Hour 4 135.5 -L77.2 74.2%
3-Aue Event 4 Hour 1 -33.6 43.6 L8.5%
Hour 2 -s0.0 -65.0 27.60/o
Hour 3 48.1 -52.5 25.5%
Hour 4 48.0 -62.4 265%
5-Aue Event 5 Hour 1 -30.8 -40.0 77.O%
Hour 2 -s0.0 -65.0 27.60/o
Hour 3 -49.0 -63.7 27.L%
Hour 4 47.4 -51.5 26.2o/o
13-Aus Event 6 Hour 1 -35.5 -47.6 L9.9%
Hour 2 -45.9 -59.6 24.9%
Hour 3 45.4 -s8.9 24.60/o
Hour 4 -45.6 -59.2 24.7o/o
Notes: Estimates of load reductions for 5 substations based on regression
model, Estimated load reductions for all ldaho lrrigation estimated as 5
substation load reduction divided by 0.77. Realization rate is the ratio of
the estimated load reduction to the opt-out adiusted nominal load.
The Program reduced irrigation loads in each event hour. The estimated load reductions ranged
from -158 MW to -31 MW and were different from zero at the 5 percent significance level.ll
The estimated reductions in Idaho irrigation loads ranged from 40 MW to 205 MW. The
" The Appendix contains estimated confidence intervals for the estimated load reductions in all event hours.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 112 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Page l2of22
estimates also exhibit the expected pattems. First, during each event, the estimated load
reduction in the first hour was the smallest, consistent with the staggering of the event initiation
for grid reliability. (During hours two, three, and four, there is very little difference in the
estimated load reductions.) Second, the load reductions over the summer reflected the seasonal
pattern of irrigation demand. The load reductions were largest in July, when loads and irrigation
demand were at their peak. The maximum load reductions on the five substations of 158 MW
and in Idaho irrigation loads of 205 MW were achieved on July l7 (event 2) during event hour 3.
The estimated load reductions were significantly smaller in June and August, when irrigation
demand was much lower.
The realization rates, which show how much load was shed relative to expectation in any given
hour, ranged from a low of 17 percent during hour 1 of event 5 to a high of 86 percent during
hour 3 of Event 2. As expected, realization rates were significantly higher in July than in June or
August because of irrigation practices and crop maturity. Nominal loads were not adjusted
downward to reflect the lower irrigation demand in June and August. Hence, the low realization
rates were due not to Program performance but rather to below average irrigation demand and
the fact that nominal rates during June and August are lower. RMP may want to consider
adjusting its estimates of nominal loads to reflect changes in irrigation demand.
Estimated Load Reductions in 2010
During events in 2010, program resources were dispatched in three or four blocks over 8 or 12
hours. Loads were dispatched outside of the 2:00p to 6:00p window because of potential adverse
impacts on the transmission and distribution system. Table 8 reports an estimate of the
maximum hourly load reduction in each block of each event during summer 2}l0.t2 Cadmus
reports the maximum in each block of hours instead of in each hour because of the large number
of event hours. The load reductions cover the Amps, Big Grassey, Bonneville, Jefferson, and
Rigby substations. It should be noted that loads that were shed between 7:00a and l0:00a or
I I :00a and I :00p resumed at the end of the event, leaving less opportunity for load reductions in
subsequent hours (note: loads thatwere were controlled between 7:00a and l0:00aand 1l:00a
and l:00p resumed at the end of the event, leaving less opportunity for load reductions in
subsequent hours).
The load impacts were greatest during 2:00p - 6:00p, when most Schedule 72a resources were
dispatched (see Table 4). The maximum hourly load reduction occurred on July 8, when
irrigation loads on the five substations were reduced by approximately 120 MW and the Idaho
irrigation load was reduced by 156 MW. Load impacts were smaller in June and August, when
irrigation demand was lower.
'' The Appendix contains estimates of the load reduction in each event hour.
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 e 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 113 of495
Case No. PAC-E-14-07
Witness: Kathryn C. HymasPage13of22Jeff Bumgarner
February 24,2011
Table 8. Estimated Load Reductions in 2010
29-Jun Event 1 5 Substations N/A -34.8 -87.0 -6t.7
AlllD lrrieation N/A -45.2 -113.0 -80.1
8-Jul Event 2 5 Substations N/A -49.5 -119.8 -85.7
All lD lrrisation N/A -il.4 -155.5 -111.3
15Jul Event 3 5 Substations N/A -44.2 -107.0 -86.6
All lD lrrieation N/A -57.4 -139.0 :L12.5
16-Jul Event 4 5 Substations -39.9 0.0 -100.s -77.7
All lD:lrrieation -51,8 0.0 -130.5 -101.0
19Jul Event 5 5 Substations -40.2 -17.9 -103.1 -83.3
All rlD Irrieation -52.2 -23.2 -133.9 -x08.2
20Jul Event 6 5 Substations -48.3 -15.1 -105.4 -82.2
All ]D lrrieation -62.7 -19.7 -136.9 -106.7
26Jul Event 7 5 Substations -36.1 -t2.2 -89.7 -75.8
All lD lrrieation 46.9 -15.9 -115.5 -98.4
2-Aue Event 8 5 Substations -2.4 -3.1 -6.7 1.3
All lD lrrisation -3.1 -4.0 -8.5 1.7
5-Aue Event 9 5 Substations -4.7 -10.0 -42.2 -31.5
All lD lrrieation -11.3 -L2.9 -54.8 -41.0
24-Aue Event 10 5 Substations -25.5 -5.0 -41.3 -31.8
All lD lrrieation -33.2 -7.8 -53.5 4L.3
26-Aue Event 11 5 Substations -20.4 -2.6 -44.3 -30.6
All lD lrrieation -26.5 -3.4 -57.5 -39.7
Notes: Estimates of load reductions for 5 substations based on regression model. Estimated load
reductions for all ldaho lrrigation estimated as 5 substation load reduction divided by 0.77.
Realization rate is the ratio of the estimated load reduction to the oot-out adiusted nominal load.
The hourly MW impacts were smaller in 2010 than in 2009 because load control resources were
dispatched over a larger number of hours. The dispatching of resources in the mondng and early
afternoon and early evening to address transmission and distribution issues meant that there was
less potential to reduce loads during peak hours. To put the 2010 load impacts in perspective,
Table 9 reports realization rates, the ratio of the estimated load impact to the nominal load in the
hour adjusted for opt outs. tt The nominal loads during peak hours were smaller in 2010 than in
2009 because programs resources were dispatched before and after the 2:00p - 6:00p period.
The realization rates account for the smaller amount of load that could have been shed benveen
2:00p and 6:00p.
13 The load opting out was subtracted from the nominal load for hours 2:00p - 6:00p for each event.
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company r www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 114 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. HymasPage14of22Jeff Bumgarner
February 24,2A11
Table 9. Estimated Realization Rates in 2010 (Based on Nominal Capacify)
29-Jun Event 1 N/A 7L.O%60.3%56.Oo/o
8-Jul Event 2 N/A 93.7%77.4%72.\o/o
15-Jul Event 3 N/A 835%76.00/o 72.9%
16Jul Event 4 N/A 0.0%74.0%70.8%
19Jul Event 5 234.9%39.8%76.7%75.8%
20Jul Event 6 282.0%33.7%82.0%74.8%
26Jul Event 7 27L.3%27.20/,63.9%69.0%
2-Aue Event 8 14.L%6.9%4.5o/o -L.2o/o
5-Aus Event 9 57.4o/o 22.5%29.7o/o 29.7%
24-Aus Event 10 757.4%73.5o/o 28.6%29.4o/o
26-4ue Event 11 72L.1o/o 6.Oo/o 30.2%28.2%
Notes: Realization rate is the ratio of the estimated load reduction to the opt-
out adjusted nominal load. Opt out loads obtained from ScheduleT2 &72A
ldaho lrrisation Load Control Programs: 2009 Credit Rider lnitiative Final Report.
During hours when events are traditionally called, the realization rates ranged between 29
percent on August 24 and 82 percent on July 20.la (We ignore the August 2 event, as load
ieductions were uniformly and abnormally low.ls; During peak irrigation demand between the
first and third weeks of July, the realization rate ranged between 77 and 82 percent of nominal
load. These impacts are slightly lower than but still close to those rn2009. The difference in
realization rates may reflect the fact that inigation demand in 2010 was relatively low because of
cooler weather throughout the summer.
Conclusions
Rocky Mountain Power asked Cadmus to evaluate the demand impacts of its Idaho irrigation
load control program. In 2010, the Program enrolled 1,975 customers and had approximately
283 MW of participating load. However, this participating load was more than RMP could
dispatch during peak hours because of transmission and distribution system constraints. This has
had the effect of reducing the Program's cost-effectiveness.
't On some event days, the maximum hourly realization rate between 7:00a and l0:00a exceeded 100 percent. This
indicates that in these hours either the Program achieved significantly greater demand reductions than expected,
or the nonrinal loads are too lorv.
15 lrrigation demand is typically very low at the beginning of August when hay is harvested and water to field crops
is turned offto initiate the crop maturation process prior to harvest. Accordingly, potential demand reductions
are very small. However, the nominal load covers all of August and does not reflect haying and crop
maturation. The small, negative demand reduction in the 6:00 p hour is statistically indistinguishable from zero.
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company o www.cadmusgroup.com
Jeff Bumgarner
February 24, 2011
Rocky Mountain Power
Exhibit No. 1 Page 1 '15 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. HymasPage15of22
Cadmus estimated the hourly load reductions from the Program in 2009 and 2010 using
regression analysis of SCADA data from five substations in Idaho. In addition, Cadmus
examined the coincidence of the program impacts with the PacifiCorp system peak demands.
There are several noteworthy aspects of the methodology:
o The impact analysis was based on SCADA data at the substation level. Since the majority
of the loads being served by these substations consist of irrigation, the amount of "noise"
in the data resulting from the variability of non-irrigation loads is expected to be minimal.
o The estimation methodology did not consider Rocky Mountain Power's education of
irrigators about efficient irrigation practices. If the benefits from education were taken
into consideration the load shifting from education would have the effect of improving
measured impact or realization rate.
The hourly analysis of loads did not account for staggering in the dispatching of loads at
the beginning and end of events for grid reliability purposes. As a result, the estimated
load impacts in the first and last hours are an estimate of the average load reduction over
the hour and may not represent the true reduction at the beginning (likely to be smaller
than estimated) or end of the hour (likely to be larger).
In the calculation of realization rates, the analysis adjusts for the required scheduling of
22 percent of the available participating loads outside of the 2:00p-6:00p time period.
This scheduling restriction was implemented in 2010 to accommodate the Grid control
voltage limitations previously noted. While this did not impact hourly realization rates, it
did have a significant effect on the difference between the nominal loads and the
aggregated reductions achieved.
The analysis of substation loads showed the following:
o In 2009. the maximum hourly load reduction on the five substations was 158 MW or 205
MW for all Idaho inigation program loads. This represented 86 percent of the nominal
program resources dispatched in that hour. The realization rates, which show how much
load was shed relative to expectation, ranged from a low of 17 percent on August 5 to the
July l7 high of 86 percent. In 2010, the maximum hourly load reduction was 120 MW
or 156 MW for all Idaho irrigation program loads. This occurred on July 8 and
represented 77 percent of the opt-out-adjusted nominal load dispatched in the hour. On
The Cadmus 6roup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 r 503.228.2992 o Fax [phone]
An Employee-Owned Company r www.cadmusgroup.com
156 MW
Jeff Bumgarner
February 24,2O11
Rocky Mountain Power
Exhibit No. 1 Page 1 16 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Page 16of22
July 20, a load reduction of 120 MW resulted in the maximum realization rate of 82
percent.
o Realization rates were calculated based on expected loads, or in the case of the Rocky
Mountain Program, loads that could safely be dispatched without adversely impacting
line voltages. This is an important distinction worth noting. Had the calculation of
realization rates been based on total participating loads, this would have resulted in lower
realization rates. As program cost-effectiveness is calculated on actual load reductions
relative to a program's costs (rather than a realization rate), realizations rates should not
be considered the definitive measurement of a program's effectiveness and value.
. The load reductions and realization rates in any year may not be representative of typical
load impacts the program might achieve because of annual variations in irrigation
demand.
o PacifiCorp system peak coincides with hours when events are traditionally called (hours
2:00p-5:00p).
Recommendations
While the Program has achieved significant load reductions. the cost-effective has been
adversely impacted by the level of participation on a megawatt basis. As noted above, in 2009
and 2010, the Program enrolled more load on some substations than it could dispatch during
peak hours because of transmission and distribution constraints. RMP could reduce enrollments
to a level consistent with the system's ability to dispatch loads. Or if technically feasible, RMP
could increase the Program's cost-effectiveness by upgrading the transmission and distribution
system to alleviate constraints on when load can be dispatched.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company o rarww.cadmusgroup.com
Rocky Mountain Power
Exhibit No. 1 Page 1 17 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. HymasPagel7of22Jeff Bumgarner
February 24,2011
Appendix
Substation Hourly Load Model
Let j:7,2.,, J index the events and h:l ,2...,H index hours of each event. Also, let MWn be the
electricity load of substation i at time (hour) t. Then (suppressing the index i) substation i's MW
demand at time t (corresponding to a week of the month, day, and hour) can be written as:
MW1:
as * a, EuapTRTZhours * a2 temp24hour6 * a3rainf allZ4hour, t
Xir=, r. w e e ko f month., + Z6a=, 6 a doy o f w e e k as * Ztr'=, y y hour o f day p, + 0 MWt -z 4 +
Zli=rl,f=rPlneventhourint*Zlj=rZf,=rQinPreeventhourint*Z!1=rL'n=rtDinposteventlrcurint*Et
The right hand side variables in the model are defined as follows:
o EvapTRT2hourl is the average evapo-transpiration rate over the previous 72 hoursl at time t.
o Temp24hourl is the average temperature over the previous 24 hours at time t.
o Rainfall24hourt is the total rainfall over the previous 24 hours.
. Weekofmonth* equals one if time t is in week w, w:l to 3, and equals zero, otherwise.
Dayac d:l to 6, and hourof daykt, k:l to 23, are defined similarly.
o Eventhoulrt eQuals one if time t is in hour h, h:l to H, of event j, j:1 to J, and equals zero,
otherwise. Preeventhour in and P osteventhour jft are defined similarly.
. tt is the error term of the model representing random influences on the demand of customer i
at time t.
The parameters to be estimated and their interpretations are as follows:
o phj is the impact of hour h of event j on demand. It is the difference between the estimate of
what demand would have been if an event had not been called (reference load) and the actual
demand in the hour.
. 6hj is the impact of hour h after event j on demand. The coefficients capture any shifting of
irrigation loads in response to the load control events.
. 0n: is the impact of hour h before event j on demand. The coefficients capture any shifting of
irrigation loads because of the load control events.
. cro is substation load at the omitted hour (Sundays at the 12 am hour in the first month).
The Cadmus Croup, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 o 503.228.2992 r Fax [phone]
An Employee-Owned Company . wvryw.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Roclq Mountain Power
Exhibit No. 1 Page 114 of495
Case No. PAC-E-14-07
VMtn€ss: Kathryn C. HymasPage18of22
o1 is the impact of average evapo-transpirationrate inthe previous 72 hours on demand. ctz
shows the impact of temperature in the previous 24 hours on demand. cr,3 rleosures the
impact of rainfall in the previous 24 hours on demand.
fi*, w:l to 3, is the impact of week of month w on demand.
66, d:l to 6, is the impact of day of the week d on demand.
yt, k:1 to 23, is the impact of hour t on demand.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 r Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Roclry Mountain Power
Exhibit No. 1 Page 1 19 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. HymasPagel9of22
Appendix Table A.1.2010 Estimated Hourly Load Reductions with 95 Percent Confidence
Intervals
30{un Event 1 Hour 1 -41.8 -55 -28 -54.3 158.4 24.8%
Hour 2 -71.8 -85 -57 -93.2 168.4 42.6%
Hour 3 -70.7 -85 -56 -91.8 168.4 42.0%
Hour 4 -66.4 -82 -50 -86.3 168.4 39.5%
17{ul Event 2 Hour 1 -111.1 -725 -97 -144.3 182.8 60.8%
Hour 2 -157.8 -772 -144 -204.9 182.8 853%
Hour 3 158.0 -172 -L44 -205.2 182.8 86.4%
Hour 4 -151.6 -165 -138 -195.9 182.8 82.9%
23-Jul Event 3 Hour 1 -702.4 -115 -89 -133.0 184.0 55.7%
Hour 2 L37.7 -L52 -L24 -178.9 184.0 74.9%
Hour 3 -138.5 -153 -t24 -180.0 184.0 75.3%
Hour 4 -136.5 -150 -t22 -177.2 184.0 74.2%
3-Aue Event 4 Hour 1 -33.6 -42 -25 -43.6 181.5 18.5/o
Hour 2 -s0.0 -58 -42 -55.0 181.5 27.6%
Hour 3 -48.1 -57 -40 -62.5 181.5 26.5%
Hour 4 -48.0 -56 -40 -62.4 181.5 26.5%
5-Aue Event 5 Hour 1 -30.8 -39 -22 -40.0 181.0 77.0%
Hour 2 -50.0 -59 -4t -5s.0 181.0 27.6%
Hour 3 -49.0 -58 -40 -53.7 181.0 27.L%
Hour 4 -47.4 -56 -39 -51.5 181.0 26.2%
13-Aue Event 5 Hour L -35.5 45 -28 -47.6 184.2 79.9%
Hour 2 -45.9 -54 -37 -s9.6 184.2 24.9%
Hour 3 45.4 -54 -37 -58.9 184.2 24.6%
Hour 4 -45.6 -54 -37 -59.2 784.2 24.7%
Notes: Estimates of load reductions for 5 substations based on regression model. Estimated load reductions for all
. ldaho lrrigation estimated as 5 substation load reduction divided by 0.77. Realization rate is the ratio of the
estimated load reduction to the oot-out adiusted nominal load.
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Jeff Bumgarner
February 24,2011
Rocky Mountain Power
Exhibit No. 1 Page 120 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Page 20 of 22
Appendix Table A.2.2010 Estimated Hourly Load Reductions with 95 Percent Confidence
Intervals
29Jun Event 1 11:00 AM 11 AM .1 PM -32.7 -42.2 -23.1 -42.4 47.O -69.6%47.O
29-Jun Event 1 12:00 PM 11 AM .1 PM -34.8 -44.0 -25.6 -45.2 47.O -74.L%47.O
29Jun Event 1 1:00 PM 11AM-1PM -28.3 -37.t -19.5 -36.8 49.0 -57.4%49.0
29-Jun Event 1 2:00 PM 2 PM.5 PM -49.2 -58.9 -39.4 -63.8 84.8 -58.0%89.3
29Jun Event 1 3:00 PM 2PM.5PM -87.0 -96.8 -77.2 113.0 7M.3 -60.3%148.8
29-Jun Event 1 4:00 PM 2PM.5PM -82.7 -92.5 -73.O -107.5 L44.3 -57.4%148.8
29Jun Event 1 5:00 PM 2PM-5PM -75.8 -8s.3 -56.3 -98.5 t44.3 -52.6Yo 148.8
29Jun Event 1 6:00 PM 6PM -67.7 -70.9 -52.5 -80.1 110.1 -56.O%110.1
8-Jul Event 2 11:00 AM 11AM-1PM 48.7 -67.5 -29.9 -63.2 so.7 -96.O%50.7
8-Jul Event 2 12:00 PM 11AM-1PM 49.6 -67.9 -31.3 -64.4 50.7 -97.8Yo 50.7
8-Jul Event 2 1:00 PM 11AM-1PM -39.0 -56.6 zL.4 -s0.6 53.0 -73.6%s3.0
8-Jul Event 2 2:00 PM 2 PM.5 PM -7t.2 -90.3 -52.t -92.4 90.5 -78.6%96.s
SJul Event 2 3:00 PM 2PM-5PM 119.8 -138.9 -100.6 -155.5 154.8 -77.4%150.7
SJul Event 2 4:00 PM 2 PM.5 PM 114.5 -133.5 -95.5 -748.7 154.8 -74.Wo 760.7
8-Jul Event 2 5:00 PM 2 PM.5 PM -104.9 -123.5 -86.2 -136.2 154.8 -67.8%160.7
8Jul Event 2 6:00 PM 6PM -85.7 -103.7 -57.6 -111.3 118.9 -72.t%118.9
15-Jul Event 3 11:0O AM 11AM-1PM -4L.3 -60.1 22.5 -53.6 50.7 -8L.4Yo 50.7
15-Jul Event 3 12:00 PM 11AM-1PM 44.2 -62.5 -2s.9 -57.4 50.7 -87.2o/o 50.7
15-Jul Event 3 1:00 PM 11 AM.1 PM -43.1 -61.0 -2s.2 -56.0 53.0 -81.3%53.0
15Jul Event 3 2:00 PM 2 PM,.5 PM -6s.6 -u.7 -46.5 -8s.2 75.6 -4s.6%96.5
15Jul Event 3 3:00 PM 2 PM.5 PM -107.0 L26.2 -87.8 -139.0 140.9 -76.OYo 760.7
15-iul Event 3 4:00 PM 2 PM.5 PM -104.4 -723.5 -85.4 -135.6 140.9 -74.1o/"160.7
15-Jul Event 3 5:00 PM 2 PM.5 PM -100.1 -118.8 -8t.4 -130.0 140.9 -71.O%160.7
15-Jul Event 3 6:00 PM 6PM -86.6 -LO4.7 -68.6 -tt2.5 118.9 -72s%118.9
16Jul Event 4 7:00 AM 7 AM. lOAM -37.5 -56.4 -18.5 -44.7 17.1 -219.r%17.t
16-Jul Event 4 8:00 AM 7 AM. 10 AM -39.9 -s8.3 2L.S -51.8 t7.1 -233.2%L7.t
15-Jul Event 4 9:00 AM 7 AM. 10 AM -35.2 -52.8 -t7.5 -45.7 77.1 -20s.5%t7.\
16-Jul Event 4 10:00 AM 7 AM. lOAM -o.2 -8.8 8.3 -0.3 t7.7 -L.4%t7.t
16-Jul Event 4 11:00 AM 11 AM .1 PM 0.0 -8.4 8.4 0.0 42.6 o.o%42.6
15-Jul Event 4 12:00 PM 11 AM .1 PM 0.1 -8.0 8.2 o.2 42.6 0.3%42.6
16-Jul Event 4 1:00 PM 11 AM .1 PM o.4 -74 8.2 0.5 44.9 0.9%44.9
15Jul Event 4 2:00 PM 2PM.5PM -50.5 -79.8 -41.5 -78.7 72.6 -83.5%88.4
16iJul Event 4 3:00 PM 2PM-5PM -100.5 119.8 -81.2 -130.5 135.9 -74.O%157.7
15-Jul Event 4 4:00 PM 2 PM.5 PM -98.6 777.7 -79.4 -128.0 135.9 -72.5%L51.7
16-iul Event 4 5:00 PM 2PM-5PM -93.4 -t12.2 -74.6 -!21.3 135.9 -68.7%15L.7
16Jul Event 4 6:00 PM 6PM -77.7 -9s.9 -59.6 -101.0 109.9 -70.8%109.9
19-Jul Event 5 7:00 AM 7 AM- 10 AM -37.4 -56.2 -18.5 -48.5 17.1 -218.SYo L7.7
19Jul Event 5 8:00 AM 7 AM- 10 AM -40.2 -58.5 -2r.8 -s2.2 17.L -234.90/"t7.7
19-Jul Event 5 9:00 AM 7 AM. 10 AM -39.8 -57.5 -22.2 -51.7 !7.1 232.8Yo L7.7
19-Jul Event 5 10:00 AM 7 AM. 10 AM -18.1 -26.7 -9.5 23.5 L7.l -10s.8%t7.t
19Jul Event 5 11:00 AM 11 AM.1 PM -17.9 -25.3 -9.4 -23.2 42.6 4t.9%42.6
19-Jul Event 5 12:00 PM 11 AM.1 PM -t6.7 -24.9 -8.6 -2t.7 42.6 -39.3Yo 42.6
19Jul Event 5 1:00 PM 11 AM.1 PM -t4.6 -22.4 -6.7 -18.9 44.9 -32.4%44.9
19-Jul Event 5 2:00 PM 2PM-5PM -61.3 -80.4 -42.2 -79.6 71.\-86.2%88.4
19{ul Event 5 3:00 PM 2PM-5PM -103.1 L22.3 -83.9 -133.9 134.5 -76.7%151.7
19-Jul Event 5 4:00 PM 2PM-5PM -10L.2 -120.3 -82.2 -131.5 134.5 -75.3o/o t9L.7
l9Jul Event 5 5:00 PM 2PM-5PM -98.6 tt7.3 -80.0 -128.1 134.5 -73.4%151.7
19-Jul Event 5 5:OO PM 6PM -83.3 -1o1.4 -65.3 -108.2 109.9 -75.4%109.9
The Cadmus Group, lnc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 .
An Employee-Owned Company . www,cadmusgroup,com
Fax [phone]
Rocky Mountain Power
Exhibit No. 1 Page 121 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Page 2l of 22Jeff Bumgarner
February 24,2011
20Jul Event 6 7:00 AM 7 AM- 10 AM -46.4 -65.3 -27.5 -60.2 L7.7 -27L.1%L7.l
20-Jul Event 6 8:00 AM 7 AM. 10 AM -48.3 -56.6 -29.9 -62.7 t7.r -282.O%t7.7
20-Jul Event 6 9:00 AM 7 AM- 10 AM -M.4 -62.r -26.8 -s7.7 L7.t -259.7%L7.t
2GJul Event 6 10:OO AM 7 AM- 10 AM -12.7 -21.4 -4.1 -16.5 r7.7 -74.5%L7.L
20-Jul Event 6 11:00 AM 11 AM.1 PM -13.6 -22.1 -5.2 -L7.7 42.6 -32.0/o 42.6
20Jul Event 6 12:00 PM 11 AM.1 PM -14.8 -23.O -6.6 -L9.2 42.6 -34.6%42.6
2GJul Event 6 1:00 PM 11 AM.1 PM -15.1 -23.0 -7.3 -L9.7 44.9 '33.7o/o M.9
2GJul Event 6 2:00 PM 2 PM.5 PM -7L.5 -90.7 -52.3 -92.9 65.2 -LO9.6Yo 88.4
20-Jul Event 6 3:00 PM 2PM-5PM -105.4 L24.8 .86.1 -136.9 724.6 -42.o%15t.7
20-Jul Event 6 4:00 PM 2 PM.5 PM -102.0 L21.2 -82.8 -132.5 724.6 -79.3Yo tSt.7
20-Jul Event 6 5:00 PM 2 PM.5 PM -98.0 -115.9 -79.7 -127.3 128.6 -76.2%75L.7
20-Jul Event 6 6:00 PM 6PM -82.2 -100.5 -63.9 -106.7 109.9 -74.804 109.9
26Jul Event 7 7:00 AM 7 AM. 10 AM -32.9 -5t.7 -L4.0 -42.7 17.7 -t92.1%L7.t
26Jul Event 7 8:00 AM 7 AM- 10 AM -36.1 -54.5 -t7.8 -46.9 17.7 -21L.3%L7.t
26Jul Event 7 9:00 AM 7 AM- 10 AM -35.0 -s2.6 -L7.3 -45.4 17.7 -204.3Yo 17.t
25Jul Event 7 10:00 AM 7 AM- 10 AM -to.4 18.9 -1.8 -13.5 77.\-50.7%77.L
26-Jul Event 7 11:00 AM 11 AM .1 PM 11.0 -19.3 -2.6 -L4.2 42.6 -25.7%42.6
26-Jul Event 7 12:OO PM 11 AM .1 PM 11.1 -19.3 -3.0 -74.4 42.6 -25.lYo 42.6
26-Jul Event 7 1:00 PM 11AM-1PM 12.2 -20.0 -4.4 -15.9 M,9 -27.2/o 44.9
26-iul Event 7 2:00 PM 2 PM.5 PM -54.7 -73.4 -3s.6 -77.O 76.9 -7t.1%88.4
26-Jul Event 7 3:00 PM 2PM-5PM -89.7 -108.9 -70.5 116.5 L40.3 -639%75\.7
26-Jul Event 7 4:00 PM 2PM-5PM -88.8 -LO7.9 -69.7 -115.3 140.3 -63.3%L51.7
26-Jul Event 7 5:00 PM 2PM-5PM -85.3 -104.1 -66.5 -110-8 140.3 -60.8%15t.7
26Jul Event 7 5:00 PM 5PM -75.4 -94.1 -57.5 -98.4 109.9 -69.OYo 109.9
26-Jul Event 8 7:00 AM 7 AM. 10 AM 24.t L4.L 34.0 31.3 77.7 L40.8%L7.7
2-Aug Event 8 8:00 AM 7 AM. 10 AM 25.3 15.6 34.9 32.8 t7.L 747.7%L7.t
2-Aus Event 8 9:00 AM 7 AM- 10 AM 29.7 20.4 38.9 38.6 L7.7 L73.5o/o t7.7
2-Aua Event 8 10:00 AM 7 AM- 10 AM -2.4 -6.6 L.7 -3.1 t7.7 -t4.!Yo L7.t
2-Aue Event 8 11:00 AM 11AM-1PM -2.O -6.1 2.O -2.6 42.6 -4.8%42.6
2-Aus Event 8 12:00 PM 11AM-1PM 2.7 -6.0 1.8 2.7 42.6 4.9%42.6
2-Aus Event 8 1:OO PM 11AM-1PM -3.1 -6.8 0.6 -4.0 M.9 -6.9%44.9
2-Aug Event 8 2:00 PM 2PM-5PM 11.5 1.5 2r.7 15.1 83.6 13.9o/o 88.4
2-Aue.Event 8 3:00 PM 2 PM.5 PM 3.8 -6.3 L4.O 5.0 146.9 2.6%15L.7
2-Aug Event I 4:00 PM 2 PM.5 PM -3.0 -13.1 7.O -3.9 146.9 -2.!/o L51.7
2-Aus Event 8 5:00 PM 2PM-5PM -6.7 -16.5 3.2 -8.5 L46.9 4.5%L51.7
2-AuE Event 8 6:00 PM 6PM 1.3 -8.2 10.9 \.7 109.9 L.2%109.9
5-Aus Event 9 7:00 AM 7 AM. 10 AM -8.0 -18.0 2.0 -10.4 15.9 47.3/o 16.9
5-Auc Event 9 8:00 AM 7 AM- 10 AM -8.7 -t8.4 1.0 -11.3 16.9 -5r.4%16.9
5-Aug Event 9 9:00 AM 7 AM. 10 AM -6.9 -16.2 2.4 -9.0 16.9 4l.OYo 15.9
5-Aus Event 9 10:00 AM 7 AM- 10 AM -8.2 -72.4 -3.9 -10.6 16.9 -48.5Yo 16.9
5-Aus Event 9 11:00 AM 11AM-1PM -8.3 -t2.5 4.2 -10.8 42.0 -L9.9Yo 42.O
5-Aus Event 9 12:00 PM 11 AM. 1 PM -8.6 L2.6 -4.7 ]t.2 42.O -20.s%42.0
5-Aus Event 9 1:00 PM 11AM-1PM -10.0 13.7 -6.2 -12.9 44.2 -22.5%44.2
5-Aug Event I 2:00 PM 2PM-5PM -19.3 -29.5 -9.2 -25.1 79.6 -24.3%87.1
5-Aus Event I 3:00 PM 2PM-5PM 4L.7 -51.9 -31.5 -54.2 t42.O -29.4%149.6
5-Aue Event 9 4:00 PM 2 PM.5 PM 42.2 -s2.4 -32.O -54.8 L42.0 -29.7%L49.6
5-Aus Event 9 5:00 PM 2 PM.5 PM -39.1 49.1 -29.7 -50.8 L42.0 -27.5%149.6
5-Auc Event 9 6:00 PM 6PM -31.5 4L.2 -2L.9 -47.0 108.3 -29.r%108.3
24-Aus Event 10 7:00 AM 7 AM- 10 AM -25.5 -35.5 -15.6 -33-2 15.9 -75t.4%L6.9
24-Aua Event 10 8:00 AM 7 AM- 10 AM -24.9 -34.6 -15.2 -32.3 16.9 -747.6%15.9
24-Aue Event 10 9:00 AM 7 AM- 10 AM -22.7 -31.4 -72.9 -28.8 16.9 L3L,3YO 16.9
The Cadmus Croup, Inc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 . Fax [phone]
An Employee-Owned Company . www.cadmusgroup.com
Rocky Mountain Power
Exhibit No. l Page 122of. 495
Case No. PAC-E-1+07
\Afrtness: Kathryn C. Hymas
Page 22 of 22Jeff Bumgarner
February 24,2011
24-AuQ Event 10 10:00 AM 7 AM- 10 AM -5.0 -9.3 -0.7 -6.5 16.9 -29.6%15.9
24-Aue Event 10 11:00 AM 11AM-1PM -s.2 -9.3 -1.0 -6.7 42.O \2.3Yo 42.O
24-Auz Event 10 12:00 PM 11AM-1PM -5.5 -9.5 -1.5 -7.t 42.0 -13.t%42.O
24-Aue Event 10 1:00 PM 11AM-1PM -6.0 -9.8 -7.8 44.2 t3.s%44.2
24-AuP Event 10 2:00 PM 2PM-5PM -32.O 42.t -21.9 -4t.6 81.9 -39.7%87.7
24-Aue Event 10 3:00 PM 2PM-5PM -40.8 -50.9 -30.5 -s2.9 744.3 -28.2o/o t49.6
24-Aus Event 10 4:00 PM 2PM-5PM -39.0 -49.0 -28.9 -50.5 tM.3 -27.0%t49.6
24-Aue Event 10 5:00 PM 2 PM.5 PM -41.3 -51.1 -31.4 -53.6 LM.3 '28.6Yo 149.6
24-Aue Event 10 6:00 PM 6PM -31.8 4L.3 -22.3 4t.3 108.3 -29.4Yo 108.3
26-AuE Event 11 7:00 AM 7 AM- 10 AM -20.4 -30.4 -10.5 -26.5 16.9 LzL.7%t6.9
26-Aus Event 11 8:00 AM 7 AM- 10 AM -19.0 -28.7 -9.3 -24.7 16.9 -t12.7%16.9
26-Auc Event 11 9:00 AM 7 AM. 10 AM -18.4 -27.6 -9.1 -23.4 15.9 -108.8%16.9
26-Aue Event 11 10:00 AM 7 AM- 10 AM -2.5 -6.7 L.t -3.2 16.9 -14.8%16.9
26-Aus Event 11 11:00 AM 11 AM.1PM.-2.0 -6.0 2.t -2.6 42.0 4.7Yo 42.0
26-Aue Event 11 12:00 PM 11AM-1PM -2.6 -6.5 r.2 -3.4 42.O -6.3%42.O
26-Aus Event 11 1:00 PM 11AM-1PM -2.5 -6.2 1.2 -3.3 M.2 -5.7/o 44.2
26-Aus Event 11 2:00 PM 2PM.5PM -31.9 -42.O -21-.8 -4L.5 84.0 -38.O%87.L
26-Aus Event 11 3:00 PM 2 PM.5 PM -44.3 -s4.4 -34.t -57.5 !46.4 -30.2%t49.6
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26-Aue.Event 11 5:00 PM 2 PM.5 PM -37.L 47.0 -27.L -48.1 146.4 -25.3/o 749.6
25-Aua Event 11 6:00 PM 5PM -30.5 40.2 -20.9 -39.7 108.3 -28.2%108.3
The Cadmus Group, Inc.
720 SWWashington Street, Suite 400, Portland, OR 97205 . 503.228.2992 c
An Employee-Owned Company . www.cadmusgroup.com
Fax [phone]
Rocky Mountain Power
Exhibit No. 'l Page 123 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
Exhibit No. 1.2
2011 Annual Report
Rocky Mountain Power
Exhibit No. 1 Page 124 of495
Case No. PAC-E-1+07
Vurtness: Kathryn C. Hymas
Rocky Mountain Power
2fi11 Energy Efficiency
and Peak Reduction
Annual Reporl Idaho
Revised August 3 2012
Roclq Mountain Power
Exhibit No. 1 Page 125 of495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
Table of Contents
Introduction and Executive Summary ............ ........4
2011 Perfornance and Activity ............ 6
Company Filings with the Idaho Public Utilities Commission............... ................... 10
Outreach and Communications. ..........12
Peak Reduction Program and Activity .................. 14
Energy Effrciency Programs and Activity ........,...17
Residential Energy Efficiency Programs and Activity ........... 19
Non-Residential Energy Efficiency Programs and Activity .....................28
Summary of 2011 Results... ................34
Balancing Account Summary .............36
Cost Effectiveness...... .......37
Appendices:............... ........ 39
Rocky Mountain Power
Exhibit No. 1 Page.1 26 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Table of Tables
Table l: Total Portfolio Performance ................ ...................... 4
Table 2: Energy EfFrciency and Peak Reduction Annual Results...... ........ 6
Table 3: Program Evaluation Timeline... ............... 9
Table 4: Load Management Portfolio Performance................ ................. l4
Table 5: Irrigation Load Control Program Performance................ .......... 15
Table 6: Energy Efficiency Portfolio Performance ............... -.................17
TableT: Residential Energy Efficiency Portfolio... .............. 18
Table 8: Commercial & Industrial Energy Efficiency Portfolio.... .......... 18
Table 9: Home Energy Savings Program Performance................ ........... 19
Table l0: Home Energy Savings Measure Performance................ .........20
Table I l: See yalater, refrigerator@ Program Performance ................ .....................22
Table 12: See yalater, refrigerator@ Results.. .....22
Table 13: Low Income Weatherization Performance.......... ....................25
Table 14: Conservation Education............. ..........27
Table 15: Energy FinAnswer Program ................28
Table 16: Energy FinAnswer by Measure Type......... ...........28
Table 17: FinAnswer Express Program ............... 30
Table 18: FinAnswer Express by Measure Type.......... .........30
Table 19: Agricultural Energy Services Program.... ..............32
Table 20: Agricultural Energy Savers by Measure ................ 33
Table 21: Revenues (Schedule l9l) by Customer Type....... ................... 34
Table 22: Expenditures (Schedule 191) by Customer Type ....................34
Table 23: Energy Efficiency kWh Saved by Customer Type....... ........... 35
Table 24: Balancing Account Activity (Schedule 191)........... ................ 36
Rocky Mountain Power
Exhibit No. 1 Page 127 oi 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Introduction and Executive Summary
Rocky Mountain Power (the "Company") working in partnership with its retail customers and
with the approval of the Idaho Public Utilities Commission (the "IPUC"), acquires energy
efficiency and peak reduction resources as cost-eflective alternatives to the acquisition of supply-
side resources. These resources assist the Company in efficiently addressing load growth and
contribute to the Company's ability to meet system peak requirements. Company energy
efficiency and peak reduction programs provide participating Idaho customers with tools that
enable them to reduce or assist in the management of their energy usage, while reducing the
overall costs to Rocky Mountain Power's customers. These resources are a valuable component
of Rocky Mountain Power's resource portfolio and are relied upon in resource planning as a least
cost alternative to supply-side resources.
Rocky Mountain Power currently offers seven energy efficiency and peak reduction programs in
Idaho. In 2011, costs associated with these programs were recovered through the Customer
Efficiency Services Rate Adjustment (Schedule 191), with the exception of the expenses
associated with the irrigation load control programl. The results of Rocky Mountain Power's
Idaho energy efficiency and peak reduction programs for the reporting period of January l,20ll
through December 31,2011 are summarized in Table I below.
Table l: Total Portfolio Performance2
(Note: See notes for Table 2 for explanation of Gross Savings and line loss assumptions)
Overall first year energy savings for 201I achieved through energy effrciency programs,
decreased approximately 27 percent while Customer Efficiency Services expenditures decreased
27 percent.
I The Idaho Public Utilities Commission, in Case No. PAC-E-I0-07, ordered that the costs associated with the Idaho
Inigation Load Control Program should be allocated as system costs and not situs to ldaho.
2 Savings and expenditures from school projects completed under the Idaho Office of Energy Resources Energy
Efficiency Incentives Agreement were removed from the PTRC, TRC and PCT cost effectiveness calculations and
results. See Appendix 1.
Sptem Benefit Revenues Collected
Sptem Benefit Ependitures (excludes lrrigation)
Total Ependitures including lrrigation
tttlW of Participaton Load (Gros s at Generation)
kWrl/r Savings (Gross at Generation)
k\Ml/r Savings (at Site)
er,elized Cost ($/k\Mr)
Lifecycle Revenue lmpact ($ft\Mt)
5,356,975
2,574,217
1't,898,261
281.4
9,513,431
8,688,218
UCT
E hibittT? y""sTfl l }'Ir"J
Cass No. PAGE-14-07
Vyrtness: Kalhryn C. Hymas
At the end of 2011, the Customer Efficiency Services balancing account had an unfunded
balance of $1,564,182.
Rocky Mountain Power's energy efficiency and peak reduction portfolio level performance for
2011 was cost effective across all five cost effectiveness tests.
Rocky Mountain Power
Exhibit No. 1 Page 129 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
20ll Performance and Activity
Program and Sector level results for 20ll are provided on the following table3. Program
Schedules are noted in parenthesis in the table.
Table 2: Energy Efficiency and Peak Reduction Annual Results
3 Savings values in this table are shown prior to any net-to-gross adjustment. The values at generation include line
losses between the customer site and the generation source. The Company's line losses by sector are9.96 percent for
residential, 9.33 percent for commercial and 9.06 percent for industrial. These values are based on the Company's
2007 Transmission and Distribution Loss Study by Management Applications Consulting published in October
2008.
Program Units
kWh/Yr Savings
(at site)
kWh/Yr Savings
(at generator)
Program
Expenditures
Low lncome Weatherization (21)10c 228,605 251,363 $253,809
Low lncome Education Program (21)168 22,848 25,123 $ 42,500
Refrigerator Recpling (1 17)710 943,17e 1,037,069 $ 107,033
Home Energy Savings (1 18)7,606 2,411,29e 2,651,341 $ 613,890
Total Residential 8,584 3,605,925 3,964,896 $ 1,017,233
Energy FinAnswer (125)1 9,727 10,634 $ 18,303
FinAnswer Epress (1 15)70 2,219.662 2,426,668 $ 632,813
Total Commercial 71 2,229,399 2,437,302 $ 651,1 16
Energy FinAnswer (125)13 478,200 521.501 $ 136,064
FinAnswer Epress ('l 15)2 14,311 15,607 $ 67,910
Agricultural Energy Services (1 55)219 2,360,393 2.57412e $ 490,980
Total lndustrial 234 2,852,904 3,111,234 $ 694,954
Total Energy Efficiency 8,688,218 9,513,432 2,363,302
Energy Efficiency Evaluation Costs $
Total System benefit E:<penditures ' All Programs $
lrrigation Load Control Erpenditures (Schedule 72 and 72A) $
210,915
2,574,217
9,324,044
Total ldaho Program Expenditures $ 11,898,261
E,hibitt"":?Y,i:113:,"Xr"J
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Major Trends and Activities
In 2011, the Company's energy efficiency program performance decreased across all customer
sectors on a kWh/year basis compared to 2010 results. Residential savings decreased by 19
percent, commercial by 35 percent, and industrial by 30 percent (including agricultural sector),
respectively.
Expenditures related to energy efficiency program delivery decreased in 2011 as compared to
2010 by 27 percent. At a sector level, the residential sector expenditures decreased by 37 percent
and commercial and industrial sectors decreased by 17 percent.
Results of the irrigation load control program reflect program changes agreed to in a stipulation
between the Company. Idaho Irrigation Pumper Association and the Idaho Public Utilities
Commission Staff, approved by Commission Order 32235 on April 27, 2071. The order froze
program participation to existing participants and the participants were required to either reduce
participating loads by I 8 percent or accept an l8 percent reduction in the incentive value. Of the
283 megawatts of connected load in 2010,258 megawatts participated during the 20ll control
season (as measured at the customer meter).
Cost Effectiveness
Consistent with the requirements outlined in the Memorandum of Understanding signed by the
Company and Idaho Commission Staff, the Company provides cost effectiveness results utilizing
five cost effectiveness tests:
l. PacifiCorp Total Resource Cost Test (PTRC)
2. Total Resource Cost Test (TRC)
3. Utility Cost Test (UCT)
4. Ratepayer Impact Test (RIM)
5. Participant Cost Test (PCT)
The PTRC (also referred to as the TRC * Conservation Adder) is a variation of the TRC test. It
includes a l0 percent benefit adder to account for non-quantified benefits of conservation
resources over supply-side alternatives. This is consistent with Northwest Power Planning and
Conservation Act.
The TRC compares the total cost of a supply side resource to the total cost of an energy
efficiency program resource, including costs paid by the customer in excess of the program
incentives provided. This test is used to determine if an energy efficiency program is cost
effective from a total cost perspective.
The UCT. also referred to as the Program Administrator Test, compares the portion of the
resource costs paid directly by the Company. This test is useful in determining the cost
effectiveness of the resource from the Company's perspective; however it does not account for
the portion of the cost that is bome directly by customers.
.-n, ont""lY I,"#i1? :'"X'";
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
The RIM test determines the impact an energy efficiency program has on rates. The ultimate
objective of an energy efficiency program is to encourage customers to use less energy, thereby
reducing energy sales. The RIM test accounts for the cost of lost revenues to the utility
associated with kWh sales reductions. The net impact of these reductions can put near-term
upward pressure on rates even when total costs are lower with a successful energy effrciency
program than with a supply-side alternative. One challenge with the RIM test however is that its
more sensitive than the other tests to differences between long-term projections of marginal costs
and long-term projections of rates, two cost streams that are difficult to quantifu with certainty.
The PCT test compares the portion of the resource cost paid directly by participants to the
savings realized by the participant. For the PCT test, bill savings are the realized benefit of
energy efficiency rather than the avoided supply-side costs.
The results for each test are provided at several levels:
l. Overall portfolio level, consolidation of all Company delivered programs
2. Load control and energy efficiency program portfolios separately
3. Residential and non-residential energy efficiency program portfolios separately
4. At the individual program level
Results of the cost effectiveness tests are included in the summary overview for each program.
Further details including key inputs and assumptions for each of the cost eflectiveness tests are
provided in the cost effectiveness section ofthis report.
E,.h i b*XrTY Y""sTl1! :'"X'1
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Program Evaluation
Rocky Mountain Power's Program Evaluation Timeline (Table 3 below) provides a summary of
the scheduled completion of program evaluations.
Table 3: Program Evaluation Timeline
As noted in Table 3, the Company completed third-parry independent process and impact
evaluation for low income weatherization. Home Energy Savings and See ya later. refrigerator@.
Findings from these evaluations will be key inputs to ongoing program design considerations as
well as inputs to future cost effectiveness determinations.
Program
Evaluation
TYPe Status
Antrcrpated
Year
Complete
t,rogram
Year(s)
Evaluated Evaluator
Low lncome Weatherization Process and
lmpact Complete 2011 2007-2009 Cadmus
Home Energy Savings Process and
lmpact Complete Q1 2012 2009-2010 Cadmus
See ya later, refrigerator@ Process and
lmpact Complete Q1 2012 2009-201 0 Cadmus
Energy FinAnswer Process and
lmpact ln Process 2012 2009-2011 Navigant
FinAnswer E<press Process and
lmpact ln Process 2012 2009-2011 Navigant
lrrigation Energy Savers Process and
lmpact ln Process 2012 2009-2011 Navigant
.,n, onl""lY #"iTlll :'"X'"J
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Company Filings with the Idaho Public Utilities Commission
The Company made several filings with the Commission regarding its energy efficiency and
peak reduction programs during 2011. Summary information conceming these filings is provided
as follows:
On January 20, 2011, Rocky Mountain Power filed an application with the Commission
requesting prospective changes to the Dispatchable Inigation Load Control program, which is
administered through Schedule 72A. This matter was subsequently assigned to Case No. PAC-E-
l1-06. Throughthe application, the Company proposed adding language to the tariffto control
participation, in an effort to address adverse impacts to the distribution system. The Company
also proposed changing the opt-out or liquidated damages penalty from a variable market price
for energy structure to a penalty that results in a decrease in participation credits or participant
incentive for each opt-out over I per season. Other proposed changes were minor administrative
adjustments to tariff language. Ultimately a stipulation was entered into by the Company, Idaho
Irrigation Pumper Association and the Idaho Public Utilities Commission Staff to set the
operating parameters for the 20ll - 2012 control seasons. The stipulation provided for the
following changes in the operation of the program:
For 20ll and 2012, the parties agreed that program participation would be targeted to
achieve 232 megawatts of participation load. The company would work to reduce
program participation from the 2010 level of 283 megawatts by 18 percent to
approximately 232 megawatts. The Company would work with participants to identifi
the approximate reduction necessary to achieve an 18 percent reduction. Participants
without the ability to identifu an 18 percent reduction by segmenting pumps would
receive a payment equal to 82 percent of their available participation credit incentive.
Incentive payments for 2011 were reduced by $1.45 per kilowatt per year to reflect
system constraints.
The Company committed to invest a minimum of $1.3 million in capital improvements to
identifl, and install equipment needed to reduce the constraints on the distribution system
prior to the start ofthe 2012 control season.
As part of the annual irrigation report, the Company agreed to complete a review of
circuit loading and recommend any needed changes or investments for the following
years' irrigation season to continue to address circuit load issues.
The dispatch program season was changed to June I - August 31 of each year.
During 20ll - 2012 program seasons no new Program participants or additional existing
participants load will be accepted into the program.
At the discretion of the Company and by agreement with selected customers, the
Company could require the manual operation of selected pumps during control events.
Opt-out provisions were modified to reflect the loss of participation credits rather than
market prices.
On February 28,2011, the Company submitted its 2010 Energy Efficiency and Peak Reduction
Balancing Account Review with the Commission.
a
a
10
E-hibi t::Y Y"iTiU :'"X'";
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
On April 27, 2011, the Commission issued an order approving the changes incorporated by the
parties in the stipulation.
On April 29, 2011, the Company submitted its 2010 Idaho Energy Efficiency and Peak
Reduction Annual Report with the Commission.
On April 29,2011, Rocky Mountain Power filed an application with the Commission seeking
authorization to suspend future program evaluations for Schedule 21, Low Income
Weatherization Services Optional for Income Qualifring Customers. This matter was
subsequently assigned to Case No. PAC-E-11-13. On January 18,2012, the Commission issued
an order denying the Company's request.
11
Roclq Mountain Power
Exhibit No. 1 Page 1 35 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Outreach and Communications
The following outreach, communications and promotional activities occurred to support Rocky
Mountain Power's energy efficiency programs in 2011.
Home Energy Savings program
Two bill inserts for the Home Energy Savings program featuring ENERGY STARo ceiling fans
and high efficiency heat pumps.
New point-of-purchase materials were developed in 20ll.These items included in-store banners
for big box retailers, compact fluorescent lighting ("CFL") cardboard kiosks, CFL booklet, CFL
shelf flap, appliance table tents, appliance/lighting danglers and room air conditioner box
stickers.
A "blue envelope" promotion ran from September 19 to November 15 encouraging the purchase
of qualiSing dishwashers, clothes washers and refrigerators. A total of 135 applications were
received as a result of this effort.
In October and November, a retail sales associate promotion ran in an effort to increase
appliance redemptions prior to Black Friday.
Two direct mail postcards promoting heat pumps and insulation were sent to approximately
1,100 customers in November.
New resource manuals, pocket guides and fact sheets were provided to retailers along with key
Home Energy Savings program information.
See ya later, refrigerator@
Newspaper ads for the See ya later, refrigerato@ recycling program ran in Idaho Falls,
Pocatello and Rexburg papers during spring months. Digital ads through Yahoo and other
websites were also apart of the program communications.
Three inserts were included in Idaho residential customer bills (April, June and August).
In October, residential customers received a mailing with a refrigerator magnet encouraging
them to recycle their old refrigerators or freezers.
Energy FinAnswer & FinAnswer Express
Ads encouraging businesses and organizations to upgrade lighting in advance of changes in
federal fluorescent lighting standards ran in Idaho Falls and Pocatello newspapers and in the
Idaho Business Review in May and July. A new handout was also developed to educate
customers on the lighting standards changes.
On May 3, Idaho trade allies were invited to a breakfast to learn about the resources available to
help them save energy and money for themselves and their clients with the FinAnswer Express
program.
12
Irrigation Load Control
Customers on Rate Schedule 10 received
prescheduled and dispatchable load control
inform customers of program modifications.
Roclq Mountain Power
Exhibit No. 1 Page 136 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
a mailing in February with information on the
options. A follow up letter was sent in April to
General Communications
Rocky Mountain Power included energy efficiency messages in radio, print and digital ads as
part of its ongoing Customer Awareness campaign that ran throughout the year.
Residential customers in Idaho received Rocky Mountain Power's Voices newsletter in bills in
January, March, April, May, July, September, October and November. Each issue covered
energy efficiency information and tips as well as other service related topics.
Other newsletters such as Energy Insights, Energy Connections and Energy Update reach
community, business and government audiences on a quarterly or monthly basis. Newsletters
included energy efficiency stories geared toward commercial, industrial and agricultural
audiences.
Rocky Mountain Power has developed a variety of brochures and event materials with
information on energy efficiency programs and resources to help customers save money.
Customers can visit vvqu.r.l,attsnrart.corn for information on energy efficiency incentive
programs, tips and other resources to save energy and money. This information is also accessible
through our main website at rvu,lv. rockv m o untai npower. net.
Rocky Mountain Power's Idaho Twitter account (@RMP Idaho) is used to promote energy
efficiency programs, recruit customers and inform customers with tips.
Additionally, Rocky Mountain Power's wattsmart Facebook page (u,r.r'u,.facebook.conr/
rock1.'mountainpor.ver.rvattsmart) points customers to energy efficiency programs and provides
conservation ideas.
13
Rocky Mountain Power
Exhibit No. 1 Page 137 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Peak Reduction Program and Activity
Peak Reduction programs assist the Company in balancing the timing of customer energy
requirements during heavy use hours; deferring the need for higher cost investments in delivery
infrastructure and generation resources that would otherwise be needed to serve those
requirements for a select few hours each year. These programs help the Company maximize the
efficiency of the Company's existing electrical system and reduce costs for all customers.
Programs targeting capacity related resources are often specific to end use loads most prevalent
in a given jurisdiction, such as the agricultural pumping loads in the Company's Idaho service
territory. The Company offers two peak reduction programs in ldaho; a pre-schedule and on-call
or dispatchable irrigation load control program. For the purpose of this report the two programs
are being combined and evaluated as one program.
Table 4: Load Management Portfolio Performancea
4 Decrement values are considered confidential on load control programs. Cost effectiveness ratios and inputs will be available
under a protective agreement. A "Pass" designation equates to a benefit to cost ratio of I or better.
Under Control (Gross - At Gen) 281 ,362 Realized Load (Gross -At Gen) 178,850
Under Control (At Site) 258,000 Realized Load (At Site) 164,000
Total bpenditures $ 9,324,044
articipation Credits $ 6,074,644
PTRC TRC UCT RIM PCT
Cost Effectiveness
14
E,h i bittTY Y"iTi13 :'"1'"J
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Irrigation Load Control (Schedule 72 and72A)
Irrigation Load Control (Schedules 72 & 72A) is offered to irigation customers receiving
electric service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service.
Participants allow the curtailment of their electricity usage as prescribed in Schedules 72 and
72Ain exchange for a participation credit. For most participants their irrigation equipment is set
up with a dispatchable two-way control system giving the Company control over their loads.
Participants are provided a day-ahead notification in advance of control events and have the
choice to opt-out of a limited number of dispatch events per season.
A summary of the program performance, expenditures, participation and cost effectiveness
results are provided in table 5:
Table 5: Irrigation Load Control Program Performance
Major Trends and Activities
The Irrigation Load Control Program was available for 52 hours from June I to August 31. The
program had the estimated potential to curtail 196 megawatts of load on July 18, the peak day.
In 201I Rocky Mountain Power had three load control events. The first load control dispatch
was on June 29 and was estimated to reduce peak system load by 168 megawatts in ldaho. This
curtailment represented 69 percent of the potential 245s n'tegawatts of available load control
customer's peak demand.
The second dispatch occurred on July 7 and was estimated to reduce system peak 160
megawatts. This curtailment represented 62 percent of the potential 258o megawatts of available
load control customer's peak demand.
The third dispatch was on July 11 and was estimated to reduce the system peak by 165
megawatts. This curtailment represented 64 percent of the potential 258 megawatts of available
load control customer's peak demand.
5 Demand fluctuates month to month. June's undiversitied demand for load control customers wurs 245 me-eawatts.
u July's undiversified demand for load control customers was 258 megawatts.
lvIW Under Control (Gross - At Gen)
Ependitures - Total
Participation Credits
Program Operations Epense
Participation (Custom ers)
Participation (Sites)
Prog ram Cost Effectirenes s
281.4
9,324,044
6,074,644
3,249,400
728
2,165
PTRC
15
.-n, ontllY LiTil3 :'"X'"J
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Idaho load control events for 201 I achieved 62 percent to 69 percent ofthe available participant
peak load.
To comply with the settlement agreement approved by the Commission on April,27,20ll,
Rocky Mountain Power studied the distribution system to determine which circuits were af,flected
the most by the [rrigation Load Control Program. It was determined that fourteen circuits on
seven substations were most susceptible to high voltage issues relating to the program. Rocky
Mountain Power engineered a solution to the problem by replacing manual capacitor banks with
automatic sensing capacitors that would turn on and off automatically to maintain acceptable
voltage levels. On these 14 circuits, 46 automatic switched capacitors were installed and 59
manual capacitors are being removed. This work is scheduled to be completed before the start of
the 2012 irrigation season.
Cost Effectiveness
The program was cost effective from all perspectives. Decrement values or avoided costs are
considered confidential on load control programs. Cost effectiveness ratios and inputs will be
available under a protective agreement. A "Pass" designation equates to a benefit to cost ratio of
I or better.
Plans for 2012
The program will be implemented during 2012 in accordance with the Idaho Public Utilities
Commission Order 32235 dated April27,20ll.
16
Rocky Mountain Power
Exhibit No. 1 Page 140 of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Energy Efficiency Programs and Activity
Energy efficiency programs deliver sustainable energy savings by improving the efficiency of
equipment such as motors, lighting and cooling equipment. Energy efficiency is also delivered
through improved weatherization of existing buildings, improving the design features of new
facilities by ensuring they are constructed to exceed code. In the industrial sector, improvements
in industrial equipment or processes can also improve energy utilization and deliver long term
energy efficiency resources. Replacement of existing functional equipment, replacement of
equipment at the end of its useful life and improvement opportunities all provide opportunities to
deliver energy efficiency resources. While each type of opportunity has unique challenges,
improvements in these areas all deliver long term energy savings over the life of the installed
equipment.
To deliver resources from these different opportunities, the Company oflers six energy efficiency
programs; three targeted to residential customers and three targeted to business customers. The
programs are designed to work in a coordinated fashion and provide complementary services
(i.e. recycle an existing refrigerator after buying a new Energy Star model) or different incentive
options (i.e., Energy FinAnswer incentives at the time a project is completed). Some programs or
program features are specifically designed to capture lost opportunities (the Design Assistance
provision in Energy FinAnswer), while other programs target retrofit or replacement
opportunities in existing structures (i.e., FinAnswer Express and Home Energy Savings).
Results for the 2011 Energy Efficiency Portfolio are presented in the following tables:
Table 6: Energy Efficiency Portfolio Performance
Syatem Benefit E4cenditures
Energy Efficiency First Year Savings kWrl/r (Gross at Generation) 9,513,431
Energy Efficiency First Year Savings kWrl/r (at Site) 8,688,218
PTRC TRC UCT RIM PCT
Portfolio Cost Effectiveness
Levelized Cost ($/k\M)
Lifecycle Revenue lm pact ($/kltttl
17
Rocky Mountain Power
Exhibit No. 1 Page 141 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Table 7: Residential Energy Efliciency Portfolio
$ 1 ,017,233
Residential EnergyEfficiencyFirstYearSavings kltthffi(Gross atGeneration) 3,964,895
Residential EnergyEffciencyFirstYearSavings k\rvhIYr(atSite) 3,605,925
PTRC TRC UCT RIM PCT
Portfolio Cost Efiectiwnes s
Lerclized Cost ($/kWr)
Lifecple Rewnue lmpact ($k!{h)
Table 8: Commercial & Industrial Energy Efficiency Portfolio
System Benefi t Ependitures
C&l Energy Efficiency First Year Savings k\Ml/r (Gross at Generation) 5,548,536
C&l Energy Efficiency First Year Savings kWhl/r (at Site) 5,082,293
PTRC TRC UCT RIM PCT
Portfolio Cost Effectirenes s
Lercl ized Cost ($/k\rvh)
Lifecycle Rerenue lmpact ($ftlttr1 $0.0000178
18
Roclry Mountain Power
Exhibit No. 1 Page 142 ot 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Residential Energy Efficiency Programs and Activity
Home Energy Savings Program (Schedute 118)
The Home Energy Savings program (Schedule ll8) provides a broad framework to deliver
incentives for more efficient products and services installed or received by Idaho customers in
new or existing homes, multi-family housing units or manufactured homes. The program is
delivered through a third party administrator hired by the Company. Program information is
available to the public at the program's web site at
http:livlwrv.homeenergysavings.netlldaho/idaho_home.htrnl and can also be accessed through
http:l/r+rryw.rockymountainpor.ver.net/env/epi.lrtml, the Company's ldaho energy efficiency
program website.
Summary of the program results for 201 I are provided in the table below:
Table 9: Home Energy Savings Program Performance
k\MrIY'r Savings (Gross - At Gen)
k\MrA/r Savings (At Site)
Erpenditures
lncentives Paid
Program Cost Effectircness
Levelized Cost ($/k\Mr)
LifecycleRerenuelmpact($/kUltrl $0.0000117
2,651,341
2,411,296
$ 613,890
$ 227,658
PTRC TRC UCT RIM PCT
19
E,h i bittTY Y"iTill'"iX,"J
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Details of 2011 measure level participation and savings are provided on the following table:
Table 10: Home Energy Savings Measure Performance
QtJote: CFL panicipation is assumed at 10 CFLs per participant.)
Major Trends and Activities
The Home Energy Savings progmm savings in 2011 decreased 78 percent in non-CFL measures
but increased I 14 percent in CFL measures. This resulted in an overall decrease of 28 percent as
compared to 2010.
The largest decrease in non-CFL participation was seen in weatherization measures. The
contractor feedback indicated that overall sales were down compared to 2010 due to economic
Home Energy Savings Measures
Clothes Washer-Tier One (1 .72 - 1.99 MEF)
Clothes Washer-TierTwo (2.O + MEF)
Clothes Washer Recycling
Dishwasher
Evaporative Cooler (Portable)
Evaporati've Coolers (Perm anenfl y lnstalled)
Electric Water Heater
Room AC
Refrigerator
lnsulation - Attic
lnsulition - Floor
lnsulation - Wall
Windows
cAc (15 SEER)
AC lnstall
CAC SiZng
AC Tune-Up
Duct Sealing - Electric
Duct Sealing - Gas
Heat Pump Upgrade
Heat Pump Conversion
HP Tune up
Ceiling Fans
Fi>dures
CFL-Specialty
CFL-Twister
'otals
ku/hrYr Savings at Generation
Unit
Measure
ment
Units
Units
Units
Units
Units
Units
Units
Units
Units
sq feet
sq feet
sq feet
sq feet
Projects
Units
Units
Projects
Projects
Projects
Projects
Units
Units
Units
Units
Units
Units
# of Units
14
1,165
o
316
o
3
58
o
350
88,673
969
3,823
9,037
2
o
1
1
0
o
2
4
1
17
110
1,220
53,616
159,382
Participants
14
1 ,16s
0
316
0
3
58
0
350
83
3
5
63
2
o
1
1
0
0
2
4
1
11
40
122
5,362
7,606
Savings
(@oss -At
Site)
3,188
283,193
0
12,881
0
975
5,26'l
o
34,125
136,974
6,439
4,949
16,475
192
o
67
30
o
0
1,622
12,588
576
1,819
10j20
41 ,146
1,838,678
2,411,296
2,651 ,341
20
E,h i bitl::Y Y""sTill :'"X'"J
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
instability and very mild summer weather. Additionally, appliance sales slowed after the
exhaustion of American Recovery and Reinvestment Act of 2009 (ARRA) funds.
Special per bulb CFL pricing was instituted in 2011 which contributed to the achievement of 100
percent of lighting goals in Idaho by the end of the year. The program also partnered with Fluid
Market Strategies and the regional Simple Steps program that helped contribute to increased
savings of 8 16,000 kW[ which represents nearly 4l percent of lighting savings for 201 1 .
A marketing campaign, which provided incentives to the sales associates in order to drive
customer participation, was conducted in the last quarter of 2011. The campaign's goal was to
promote appliance measures such as dishwashers, clothes washers and refrigerators and resulted
in a total of 135 applications received from the top retailers such as Sears, Denning's, and Home
Depot. This promotion contributed significantly to appliance savings for the program. A similar
promotion will be considered again in 2012.
Cost Effectiveness
The program was cost efflective from
Appendix I provides detailed inputs used
Program Evaluation
all perspectives except the Ratepayer Impact Test.
in the cost eflectiveness analysis of this program.
See comments under the Program Evaluation heading in the 201I Perforrnance and Activities
section of this report for evaluation activities related to this program.
Plans for 2012
The program is focusing on targeted retailer outreach rn 2012, as six retailers in Idaho account
for 80 percent of appliance redemptions. Program staff is also focusing on the Qualified
Weatherization Contractor Network and bringing new trade allies onto the program. By co-
branding, placing product, and co-sponsoring promotions. the program expects to increase
participation.
21
E,h i bi,tTY y"iTill
"'"X'1Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
See ya later, refrigerator@ (Schedule 117)
The Residential Refrigerator Recycling Program (Schedule I l7) is available to Idaho residential
customers through a Company contracted third-party program administrator. Older refrigerators
and freezers which are less efficient, yet operational, are taken out of use permanently and
recycled in an environmentally responsible manner. The program's objective is to permanently
retire these older and less eff,rcient refrigerators and freezers from the market and recycle the
units in order to avoid their re-entry or resale on the secondary appliance market. Program
awareness is generated through mass media advertising channels as well as Company
communications such as the program's web site, bill stuffers, and customer newsletters. In
addition to free pick-up and a nominal cash incentive, participants receive an energy efficiency
packet consisting of two ENERGY STAR@-certified compact fluorescent light bulbs. a
refrigerator/freezer thermometer, and energy education materials.
A summary of the program results for 2011 are provided in the table below.
Table LL: See ya later, refrigerator@ Program Performance
Details of 2011 measure level participation and savings are provided on the following table:
Table L2: See ya later, refrigerator@ Results
Itelngerator
Recycling Measure Unit Count
Per Unlt Savrngs
(kWh/Yr)
Gross l'avlngs
(kwh/Yr)
Refrigerator 542 1,',t49 622.758
Freezer 168 1,590 267,120
Total Units Recycled 710 889,878
Energy Savings Kits 658 8'1 53,298
Total (At Site)943,176
Total (At @neration)1,037,069
kWh Savings (Gross -AtGen) 1,037,069
kWh SaMngs (At Site) 943,176
E4renditures $ 107,033
lncentives Paid $ 21,300
PTRC TRC UCT RIM PCT
Program Cost Effectirenes s
Levelized Cost ($/k\A/lr)
Lifecycle Revenue lmpact ($/kUltrl $ 0.000006024
22
=,.n,onT,::Y[iTiil'","X,";Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Major Trends and Activities
Program participation in 2011 decreased approximately l0 percent from 2010 (in terms of unit
volumes). A direct mail campaign in October involved approximately 20,000 pieces, and
resulted in strong Q4 program activity.
Environmental Attributes
In terms of the impact of the program on the environment, processing the 710 harvested units
resulted in the recycling of more than 44 tons of metal, 7 tons of plastics, 1 ton of tempered
glass, the recovery or destruction of more than 300 lbs of refrigerant, and the destruction of more
than 400 and 100 lbs of CFC-11 and HCFC-l4lb, respectively, contained in foam insulation.
Cost Effectiveness
The 2011 See ya later, refrigerator@ program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix 1 provides detailed inputs used in the cost effectiveness
analysis of this program.
Program Evaluation
See comments under the Program Evaluation heading in the 2011 Perfornance and Activities
section of this report for evaluation activities related to this program.
Plans for 2012
Goals in2012 call for 1,000 units to be collected and recycled. Based on successful experiences
in late 2010 and late 2011, direct mail will be used again in the May-June time frame. The retail
element, begun in 2011 at national chains such as Sears and Best Buy, will be expanded to
include R.C. Willey and stand-alone "mom and pop" stores. In addition, cross promotional
opportunities with the Home Energy Savings program will be used in retail stores (e.g., through
point-of-sale fl yer placements).
23
Rocky Mountain Power
Exhibit No. 1 Page 147 of 495
Case No- PAC-E-1+07
Wtness: Kathryn C. Hymas
Low Income Weathertzation (Schedute 21)
The Low Income Weatherization Services program (Schedule 21) is available through a
partnership with Eastern Idaho Community Action Partnership (EICAP) in Idaho Falls and South
Eastern Idaho Community Action Agency (SEICAA) in Pocatello. These partnerships allow for
leveraging of Company funding with federal grants available to EICAP and SEICAA, increasing
the number of homes served. Rocky Mountain Power's funding in 201I provided rebates that
covered 85 percent ofthe cost ofapproved energy efficiency measures.
Income eligible households receive energy efficiency services at no cost. Participants can be
either homeowners or renters residing in single-family homes, manufactured homes and
apartments.
Table 13 summarizes the program results for 2011. Program expenditures totaled $253,809.
Funds received by the agency from other sources (state or federal funding) are not included.
Rocky Mountain Power's program provided funding towards the weatherization of 100
qualiffing homes in 201I with an average program cost per home of $2,538.
24
Roclq Mountain Power
Exhibit No. 1 Page 148 of495
Case No. PAC-E-1+07
Ufilness: Kathryn C. Hymas
Table 13: Low Income Weatherization Performance
Major Trends and Activities
Weatherization completions in 2011 more than doubled compared to 2010 program activities.
The Low Income Weatherization Program tariff was revised as of December 28, 2010,
increasing the Company's reimbursement from 75 percent of costs on approved measures to 85
percent, and annual funding was increased from $150,000 to $300,000.
k\Mr/yr Savings (At Site)
kWhlyr Savings (Gross - At Cren)
Ependitures
lncentiws Paid
Participation - Total # of CompletediTreated Homes
Floor lnsulation
Wall lnsulation
Duct lnsulation/Seali ng
Attic Ventilation
lnfiltration
Water Pipe lnsulation and Sealing
Water Heater Repair
Water Heater Replacement
Furnace Repair/Tune-up
Fumace Replacement
Health & Sabty
Replacement Windows
Thermal Doors
Compact Fluorescent Light Bulbs (CFLs)
Number of Specffic Measures
Replacement Refigerator
3t
30
b
I
29
57
88
5
1
36
6
43
37
36
97
TotalProgram Costs PTRC TRC UCT RIM PCT
Program Cost Effectireness I O.at z
Lereriad cost($rkwr) f0lP6-3
Lifecple Rewnue lmpact($k\Mr) $ 0.000005332
Program Cost Efiecliwness | 0.957
Lerclized Cost ($/kvvh) I OIO?8
Lifecycle Rerenue lmpact ($k\luh) $ 0.000004542
Results without additional data request costs PTRC TRC UCT RIM PCT
0.1078
25
Rocky Mountain Power
Exhibit No. 1 Page 149 of495
Case No. PAC-E-1rl-o7
vvitness: Kathryn C. Hymas
Cost Effectiveness
An evaluation of Low Income Weatherization Services Optional for Income Qualiffing
Customers program was completed in 201I by a third party administrator for program years
2007 through 2009.
The Company recognizes the importance of the Low Income Weatherization Program and the
benefit to the customers by reducing kWh usage and helping to make participant's bills more
affordable, as well as increasing their comfort. However, as described in the Low-Income
Weatherization program evaluation, due to many factors the third party evaluator determined that
the program was not cost-effective.
Program Evaluation
See comments under the Program Evaluation heading in the 2011 Perfornance and Activities
section of this report for evaluation activities related to this program.
Plans for 2012
We anticipate 2012 weatherization completions will be fairly consistent with 201 I results.
26
Rocky Mountain Power
Exhibit No. 1 Page 150 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Conservation Education
Rocky Mountain Power committed to provide a total of $50,000 for an energy education
component for the Low Income Weatherization program (Schedule 21). This commitment was
made through a stipulation dated April 16,2009, in Case No. PAC-E-08-01. The Company
provided $7,500 in funds for energy efficiency kits to be distributed through the Conservation
Education component in May, 201A, and a total of $42,500 in May. 201I to Eastem Idaho
Community Action Partnership (EICAP) and South Eastern Idaho Community Action Agency
(SEICAA) to cover their expenses in providing these services.
The Conservation Education is designed to provide a group education session and an in-home
education session to participants, as well as an energy efficiency kit with easy-install measures.
The energy efficiency kits include one 13 watt CFL, one 19 watt CFL, one23 watt CFL, ten
outlet gaskets, one kitchen aerator, one refrigerator temperature card and one luminescent night
light. The agencies began offering these services in May, 2011.
A total of 168 households completed the conservation education component in 201l. Since it is
designed to reach 500 households with the $50,000 funding, it is very likely these conservation
education services will continue through 2012 with the monies provided in 2010 and 201 I .
Table 12 summarizes the program results for 2011. No savings are reported from behavioral
changes that may have resulted from the education sessions.
Table 14: Conservation Education
kWh/yr Savings (At Site) 22,84t
kWr/yr Savings (Gross - At Gen) 25,12i
Ependitures $ 42,500
Completed households 16
Major Trends and Activities
The development of the curriculum and implementation of the conservation education
component for Rocky Mountain Power customers was delayed as staff from the Community
Action Partnership Association of Idaho (CAPAI), EICAP and SEICAA were focusing on the
implementation of the Idaho Power education program. These services were offered to our
customers beginning in May, 2011.
Plans for 2012
We anticipate that 2012 Conservation Education completions will be approximately the same as
in 201 1 or greater. As of December 37, 2011, there were 332 kits remaining of the 500 Rocky
Mountain Power funded in 2010.
27
Rocky Mountain Power
Exhibit No. 1 Page 151 of495
Case No. PAC-E-14-07
Vlftness: Kathryn C. Hymas
Non-Residential Energy Efficiency Programs and Activity
Energy FinAnswer (Schedule 125)
The Energy FinAnswer program is offered to commercial (buildings 20,000 square feet and
larger) and industrial customers. The program provides Company-funded energy engineering,
incentives of $0.12 per kWh of first year energy savings and $50 per kW of average monthly
demand savings up to a cap of 50 percent of the approved project cost. The program is designed
to target comprehensive projects requiring project specific energy savings analysis and operates
as a complement to the more streamlined FinAnswer Express program. In addition to customer
incentives, the program provides design team honorariums (a finder fee for new projects) and
design team incentives for new construction projects exceeding current Idaho energy code by at
least 10 percent.
A summary of the program results are provided in the table below:
Details of 201 I savings by type of measure are provided on the following table:
Table 16: Energy FinAnswer by Measure Type
Energy FinAnswer kWh/Yr Savings (at site) by Measure Type
Compressed Ar 128,051 260/o
Lighting 14,241 3o/o
lVkrtors
Refrigeration
302j20 6204
43.s15 9%
487,927
Table 15: Energy FinAnswer Program
k\MrA/r Savings (Gross - At Gen)
k\Mr/Yr Savings (At Site)
E:rpenditures
lncentives Paid
Program Cost Effectircness
Level ized Cost ($/kVVh)
Lifecycle Rerenue lmpact ($/k\ntnl $ 0.000001387
532,135
487,927
$ 154,367
$ 42,932
PTRC TRC UCT RIM PCT
28
on,ontTYY"iTru:'"I'"J
Case No. PAC-E-1+07
Wtness: Kathryn C, Hymas
Major Trends and Activities
A total of 18 Energy FinAnswer projects were completed in 2011 compared to l0 in 2010.
Program specific energy savings decreased 67 percent and expenditures decreased 58 percent
during 2011 compared to 2010. The Company continues to market the program through its
Customer and Community Managers and network of trade allies in concert with the FinAnswer
Express program.
Cost Effectiveness
The 2011 Energy FinAnswer program was cost effective from all perspectives except the
Ratepayer Impact Test. Appendix I provides detailed inputs used in the cost effectiveness
analysis of this program.
Program Evaluation
See comments under the Program Evaluation heading in the 2011 Perfornance and Activities
section of this report for evaluation activities related to this program.
Plans for 2012
Continue to monitor actual and forecasted participation and assess the potential impacts of
program modifications similar to those implemented in other markets.
29
.,n, onl,llY I"iTiH :'"1,"J
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
FinAnswer Express (Schedule 115)
The FinAnswer Express program (Schedule 115) is available to Idaho business customers
excluding those served on Schedule 10, which are eligible for program services through the
Irrigation Energy Savers program. The FinAnswer Express program is available to help
customers improve the efficiency of their new or replacement lighting, HVAC, motors, building
envelope and other equipment by providing prescriptive or pre-defined incentives for the most
common efficiency measures listed in the program incentive tables. The program also includes
custom incentives and technical analysis services for measures not listed in the program
incentive tables that improve electric energy efficiency. The program is designed to operate in
conjunction with the Energy FinAnswer program. Although incentives available vary, the
program provides incentives for both new construction and retrofit projects.
The program is primarily marketed through local trade allies who receive support from Company
provided sales and training team. The lists of participating vendors posted on the Company
website include 21 lighting, 32 HVAC,27 motor, and 4 other equipment trade allies.
A summary of the program results are provided in the table below:
Table L7: FinAnswer Express ProgramT
Details of 2011 savings by type of measure are provided on the following table:
Table 18: FinAnswer Express by Measure Type
FinAnswer E><press kWh/Yr Savings (at site) by Measure Type
Lighting 1 ,584,337 7'lo/o
Non-Lighting 649,636 29o/o
2,233,973
7 Savings and expenditures from school projects completed under the Idaho Office ofEnergy Resources Energy
Efficiency Incentives Agreement were removed from the PTRC, TRC and PCT cost effectiveness calculations and
results. See Appendix l.
Savings (Gross - A Gen) 2,442,275
k\MuYr Savings (A Site) 2,233,973
Erpenditures $7OO,723
lncentives Paid $356,726
PTRC TRC UCT RIM PCT
Program Cost Effectirrenes s
Lerclized Cost ($/kVvh)
Lifecycle Rerenue lmpact ($/k!run) $ 0.00001 55022
30
Rocky Mountain Power
Exhibit No. 1 Page 1 54 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Major Trends and Activities
Participation from customers in the goverrlment and education sectors was strong in 2011,
accounting for almost 70 percent of program's energy savings.
On May 3, 2011, Rocky Mountain Power provided lighting and mechanical/non-lighting
program training in combination with the Northwest Trade Ally Network (NW Tan) with
technical lighting training in Idaho Falls. Forty- one individuals attended the program training.
Cost Effectiveness
The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix I provides detailed inputs and assumptions used in the cost effectiveness analysis of
this program.
Program Evaluation
See comments under the Program Evaluation heading in the 201I Perforrnance and Activities
section of this report for evaluation activities related to this program.
Plans for 2012
The Company plans to continue to provide marketing and trade ally outreach to target customers
with Tl2 fluorescent lighting to provide information on changes in federal lighting standards
coming on July 14,2012. Site outreach is continuing for trade allies with more resources and
field staff visiting the area including lighting technical specialists and non-lighting mechanical
outreach trade ally coordinators. These field visits are specifically designed to support the local
trade allies with project closure and processing the applications for incentives.
31
."n, ontTY l"iTfl I :'"X'"J
Case No. PAC-E-1+O7
Witness: Kathryn C. Hymas
Agricultural Energy Services (Schedule 155)
Agricultural Energy Services, marketed as Irrigation Energy Savers (Schedule 155), was
available in 20ll to Idaho irrigation customers taking retail service on Schedule l0 through a
Company contracted third-party program administrator. The program design is intended to be the
energy efficiency complement to the Irrigation Load Control programs offered under Schedules
72 &72A.
The 201I program included the following customer service and measure components:o Equipment Exchange - Provides new standard sprinkler nozzles, gaskets, and drains to
replace worn equipment on hand lines, wheel lines and solid set sprinklers systems.o Pivot and Linear Equipment Upgrades - Incentives are provided for certain pivot and
linear system measures including sprinkler packages, pressure regulators, and drains. The
list of prescriptive incentives is not designed to be exhaustive and other pivot measures
are eligible for incentives if energy savings can be calculated and the customer incurs
costs to make the changes.o System Consultation - This service provides a simple site specific audit of a customer's
irrigation system to promote irrigation water management and identifu energy savings
opportunities. This consultation provides information prior to a full pump test.o Pump Testing - The pump test includes directly measuring pump lift, flow, pressure, and
electrical demand and is performed after the pump has been screened and the owner's
fi nancial investment criteria understood.o System Analysis - The program provides energy engineering to help growers quantifo
the costs and savings of their system efficiency upgrades. Oftenthese upgrade decisions
are made in conjunction with operational production change considerations impacting a
growers equipment needs. Incentives are based on a standard formula tied to costs and
first year energy savings.
A summary of the program results for 2011 are provided in the table below.
Table 19: Agricultural Energy Services Program
k\MrlYr Savings (Gross - At Gen) 2,574,126
k\MA/r Savings (Pt Site) 2,360,393
Erpenditures $ 490,980
lncentives Paid $ 224,890
PTRC TRC UCT RIM PCT
Program Cost Efiectiwness
Levelized Cost ($/kW'r)
Lifecycle Revenue lmpact ($/kwtr' $ 0.0000046450
0.o757
32
'- n, ont""lY L"nTill :'"X'?
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Details of 201 I savings by type of measure are provided on the following table:
Table 20: Agricultural Energy Savers by Measures
Agricultural Energy Savers kWh/Yr Savings by Measure Type (at Site)
Equipment Exchange & PiroULinear Upgrade
System Design
1,697,132 72yo
663,259 280h
2,360,391
Major Trends and Activities
The 2011 savings and expenses were 6 percent and 23 percent, respectively, lower compared to
2010 program savings and expenditures.
During 2011,101 site visits were completed to obtain system information used in either a system
consultation or an energy analysis evaluation as a part of the Agricultural Energy Services
Program. During the same year,2l post installation inspections were completed to verifii project
installation and energy savings.
The following outreach and event activities were completed for the program in 201 1:
o Maintained a booth at the Eastem Idaho Ag. Expo and Potato School January 18 - 20, to
promote the program and provide program information to customers.o Maintained a booth and met with customers at the Rain For Rent customer appreciation
day in Idaho Falls on February 24.o Maintained a booth and met with customers at the Valley Implement customer
appreciation day in Preston onFebruary 24.o Met with each of the program participating dealers and provided a summary report of
incentives provided to their customers through the program, provided updated program
applications and information, and answered program related questions.
Cost Effectiveness
The program was cost effective from all perspectives except the Ratepayer Impact Test.
Appendix I provides detailed inputs and assumptions used in the cost effectiveness analysis of
this program.
Program Evaluation
See comments under the Program Evaluation heading in the 2011 Perfornance and Activities
section of this report for evaluation activities related to this program.
8 Table totals may not add up exactly due to rounding
33
Rocky Mountain Power
Exhibit No. 1 Page 157 of495
Case No. PAC-E-14-07
VMtness: Kathryn C. Hymas
Summary of 2011, Results
Table 21: Revenues (Schedule 191) by Customer Type
lndustrial
Table 22: Expenditures (Schedule 191) by Customer Type
(Note - Table 22 does not include Irrigation Load )
u
Rocky Mountain Power
Exhibit No. 1 Page 1 58 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Table 23: Energy Efficiency kWh Saved by Customer Type
35
E hibi tTY Y"iTill :'"X,";
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Balancing Account Summary
Energy efficiency and peak reduction activities are funded by revenue collected through
Schedule l9l, Customer Efficiency Services Rate on customer bills. Expenses for energy
efficiency programs are charged as incurred and booked to the balancing account. The
balancing account activity for 201I is outlined in the table below.
Table 24: Balancing Account Activity (Schedule 191)
Column Explanations:
Monthly Program Costs - Fixed Assets: Monthly expenditures for all energy efficiency and peak reduction
program activities.
Accrued Costs: Program costs incurred during the period not yet posted.
Rate Recovery: Revenue collected through Schedule 191, Customer Effrciency Service Rate.
Carr.ving Charge: Monthly "interest" charge based on "Accumulated Balance" of the account. The current
"interest rate" for the Accumulated Balance is I percent per year.
Accumulated Balance: Current balance of the account. A running total of account activities. If more is
collected in "Revenue" than is spent for a given month, the "Accumulated Balance" will be decreased by
the net amount. A negative accumulative balance means cumulative revenue exceeds cumulative
expenditures; positive accumulative balance means cumulative expenditures exceed cumulative revenue.
Accrual Basis Accumulative Balance: Current balance of account including accrued costs.
At the beginning of 2011, the unfunded balance was approximately $3.846 million and decreased
by approximately $2.282 million during the year. The unfunded balance at the end of 2011 is
$1.564 million which includes the accrued cost.
January
February
Nlarch
April
Ivlay
June
July
Argust
September
October
November
December
2010 totals
Rate Recovery
$ (418,081.5s)
$ (338,071.76)
$ (310,853.16)
$ (284,248.86)
$ (3s1,043.79)
$ (455,326.01)
$ (785,015.77)
$ (719,628.69)
$ (570,028,01)
$ (38e,845.34)
$ (353,022.44)
$ (381,809.72)
Carrying
Charge
$ 3,070.00
$ 2,890.00
$ 2,816.00
$ 2,761.00
$ 2,660.00
$ 2,479.00
$ 2,103.00
$ 1,627.00
$ 1,260.00
$ 980.00
$ 821.00
$ 883.00
Balance as of 1 2/31/1 0
$ 3,845,843
Cash Basis
Accumulated Bahnce
$ 3,525,744.00
$ 3,413,149.61
$ 3,348,026.29
$ 3,280,352.36
$ 3,106,148.69
$ 2,846,893.26
$ 2,202,249.s0
$ 1,704,340.84
$ 1,319,776.16
$ 1,033,991.58
$ 937,787.57
$ 1 ,183,201 .68
Accrual Basis
Accumulated
Balance
1,564,181.86
Monthly Program
Cost - Fixed Assets Accrued Costs
$ 94,913.02
$ 222,587.37
$ 242,913.84
$ 213,813.93
$ 174,180.12
$ 193,591.58
$ 138,269.01
$ 220,093.03
$ 184,203.33
$ 103,080.76
$ 255,997.43
$ 626,340.83 380,980.18
$ 2,669,984.25 $ 380,980.18 $ (5,356,975.10) $ 24,350.00
36
Rocky Mountain Power
ExhibitNo. I Page 160of495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Cost Effectiveness
Introduction
The cost effectiveness of individual programs operated by the Company for 201 I are calculated
using actual expenditures and reported savings. Cost-effectiveness is provided at the individual
program. load management portfolio, residential energy efficiency portfolio, non-residential
energy efficiency portfolio, combined energy efficiency portfolio, and overall energy efficiency
and peak reduction program portfolio levels. Deemed savings estimates where applicable were
the same as those used in the planning estimates.
Energy savings shown in this report are gross savings and the impact of line losses is indicated
with an at "site" or at "generation" designation. Line losses are based on the Company's 2007
line loss study. Net-to-gross assumptions are consistent with planning estimates. The energy
savings attributed to each program are shaped according to specific end-use savings (the hourly
calculation of when energy is used for the various end-use measures from which the savings are
derived). Program costs and the value of the energy savings are then compared on a present
value basis with the Company's 20ll Integrated Resource Plan (lRP) calculated decrement
values for energy efficiency resource savings and avoided capacity investments. The energy
efficiency resource decrement values are fully shaped to represent the 8,760 hourly values that
exist within a calendar year. By matching the hourly savings with the hourly avoided costs, both
energy and capacity impacts of energy efficiency savings are recognized.
The cost/benefit analysis of the load management programs are based on the avoided value of
peak or capacity investments. For purposes of calculating program cost-effectiveness no energy
savings are included for the load management programs, only a shift of when the energy is used
away from the peak load hours. The five California Standard Practice Manual cost effectiveness
tests were utilized in the cost benefit analysis for both energy efficiency and load management
programs. Further details are available in Appendix l.
37
=- n, ontllY I""nTi1?
t","xr"J
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Key Assumptions for Cost Effectiveness Calculations:
Cost Effectiveness calculations for programs and measures (or measure groups) within each
program will be detailed in the tables in Appendix l.
Global Assumptions used in all cost effectiveness calculations include:
Assumption Value
Discount Rate 7.17%
Line Losses (Idaho Specific)
Residential 9.95s%
Commercial 9.326%
Industrial 9.055%
Source
201I Integrated Resource Plan
2007 MAC Line Loss Study
2007 MAC Line Loss Study
2007 MAC Line Loss Study
Key elements that go into the cost effectiveness calculation for each program include:
o KWkWh Savings Grosso AdministrativeExpenseso Incentives Paido Total Utility Costs - including administration and evaluation
o Gross Customer Costso Net To Gross Ratioo Measure Lifeo Avoided Cost/Resource Decrement Value
Please reference Appendix l, Cost Effectiveness 20ll Idaho Energy Efficiency and Peak
Reduction Annual Report for additional information on the key assumptions and inputs for cost
effectiveness calculations for each program.
38
Roclry Mountain Power
Exhibit No. 1 Page 162 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Appendices:
Appendix 1 - Cost Effectiveness 201I Idaho Energy Efficiency and Peak Reduction
Annual Report
39
Rocky Mountain Power
Exhibit No. 1 Page 163 of495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
vRocKYMOUNTAIN
YPOWER\ A DTVTSTON OF PACTFICORP
Appendix 1
Cost Effectiveness
2011 ldaho Energy Efficiency and Peak
Reduction Annual Report
Rocky Mountain Power
Revised August 3,2012
=,,n,0n1"":? I":Tfl I :'"ffJ
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Table of Contents
Portfolio and Sector Level Cost Effectiveness ....... 3
Program Level Cost Effectiveness...... .................... 5
Home Energy Savings Program - Schedule I 18 ............ ........................ 5
Refrigerator Recycling (See ya later, refrigerator@) - Schedule 117............. .......... 6
Low Income Weatherization- Schedule 2l ............. ............7
Energy FinAnswer - Schedule 125............. ........ 9
FinAnswer Express - Schedule 115 ............ ..... l0
Agricultural Energy Services (lrrigation Energy Savers) - Schedule 155 ...............................12
Rocky Mountain Power
Exhibit No. 1 Page 165 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Portfolio and Sector Level Cost Effectiveness
The overall energy efficiency and peak reduction portfolio and component sectors were all cost
effective on a PacifiCorp Total Resource Cost Test (PTRC), Total Resource Cost Test (TRC),
Utility Cost Test (UCT), Ratepayer Impact Test (RIIIQ and Participant Cost Test (PCT) basis.
Decrement values are considered confidential on load control programs. Cost effectiveness ratios
and inputs will be available under a protective agreement. A 'oPass" designation equates to a
benefit to cost ratio of 1 or better.
The following table provides the results of all five cost eflectiveness tests.
2011 Portfolio and Sector Cost Effectiveness Summary
201I Total Portfolio including Load Control
201I Total Energy EfiErciency Portfolio
201I C&I Energy Efficiency Portfolio
2011 Residential Energy Efficiency Portfolio
201I lnigation Load Control
Effectiveness Test
PTRC TRC
4.348 3.953
1.240 1.127
1.296 1.178
1.173 L066
Pass Pass
UCT RIM PCT
2.224 r.73s 4.937
1.611 0.694 2.166
1.813 0.794 1.655
1.376 0.s82 3.341
Pass Pass NA
Sector and Program Level Cost Effectiveness Summaries:
The cost effectiveness results for the sector level are aggregations of the costs and benefits from
the component programs. The inputs and assumptions that support these results are contained in
the program level cost effectiveness results.
2011 Total Portfolio Energy Efliciency
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0783 $3,U4,424 $4.147,320 $802,896 1.240
Total Resource Cost Test (TRC) No
Adder 0.0783 $3,U4,424 $3,770,291 $425,867 1.127
Utilitv Cost Test ruCT)0.0550 $2,531,717 $4,077,333 $1,545,617 1.61 1
Rate lmpact Test (RlM)$5,876,251 $4,077,333 ($1 ,798,918)0,694
Participant Cost Test PCT)$2,191,770 $4,746,620 $2,554,850 2.'t66
Lifecycle Revenue lmpacts ($/kwh)$0,00003601 57
Rocky Mountain Power
Exhibit No. 1 Page 166 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2011 Residential Energy Efficiency Portfolio
Total Resource Cost Test (PTRC)
+ Conservation Adder 0.0803 $1,514,245 $1,776,200 $261,955 1.173
Total Resource Cost Test (fRC)
No Adder 0.0803 $1,514,245 $1,614,727 $100,482 1.066
Utilitv Cost Test (UCT)0.0622 $1,173,187 $1,614,727 $441,540 1.376
Rate lmpact Test (RlM)$2,776,108 $1,614,727 ($1,161,381)0.582
Paffcipant Cost fest (PCT)$664,090 $2,218,950 $1,554,860 3.341
Lifecycle Revenue lmpacts ($/kwhl $0.000023251 7
2011 C&I Energy Efficiency Portfolio
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0762 $1,830,179 $2,371,120 $540,941 1.296
Total Resource Cost Test (TRC) No
Adder 0.0762 $1,830,179 $2,155,564 $325,385 1.178
Utilitv Cost Test (UCT)0.0493 $1,358,529 $2,462,606 $1 ,104,077 1 .813
Rate lmpact Test (RlM)$3,1 00,143 $2,462,606 ($637,537)0.794
Participant Cost Test (PCT)$'1,527,679 $2,527,670 $999,991 1.655
Lifecycle Revenue lmpacts ($/kwh)$0.00001 78050
Rocky Mountain Power
Exhibit No. 1 Page 167 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Program Level Cost Effectiveness
llome Energy Savings Program - Schedule 118
The tables below present the cost-effectiveness findings of the Idaho Home Energy Savings
program based on Rocky Mountain Power's 2011 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).
Cost-effectiveness was tested
decrement.
using the 2011 IRP 35o/o east residential whole house load factor
Table L: Home Energy Savings
Annual Program Costs
Table 2: Home Energy Savings
Savings by Measure Type
Lighting $8,499 $962 $52,374 $61,835 $247,9s6
Appliance $223,881 $25,U7 $136,216 $385,444 $267,439
Home lmprovement $104,971 $11,885 $36,1 1 9 $152,974 $44,886
HVAC $9,600 $1,087 $2,950 $13,637 $8,436
Total $346,951 $39,281 $227,658 $613,890 $568,716
Liohtino 1,879,824 1030/o 1,936,219 85%1,645,786 5.0
Appliance 351,561 1610/o 566,013 86%486,771 14.0
Home lmprovement 164,836 75%123,627 87Yo 107,555 30.0
HVAC 15,075 99%14,924 86%12,83s 14.0
Total 2,411,296 2,640,783 2.252,948
Table 3: IRP 35"/oLoad Factor Decrement
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0656 $954,947 $1,381,256 $426,309 1.M6
Total Resource Cost Test (TRC) No Adder 0.0656 $954,947 $1,255,687 $300,740 1.315
Utilitv Cost Test (UCT)0.0422 $613,890 $1,255,687 $641,798 2.045
Rate lmpact Test (RlM)$1,843,888 $1,255,687 ($588,201 )0.681
Participant Cost Test (PCT)$664,090 $1,664,734 $1,000,644 2.507
Lifecycle Revenue lmpacts ($/kwh)$0.00001 17762
Discounted Participant Payback (years)1.96
Refrigerator Recycling (See ya later, refrigerator@) - Schedule ll7
The tables below present the cost-effectiveness findings of the Idaho See-Ya-Later Refrigerator
program based on Rocky Mountain Power's 20ll costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).
Cost-efiflectiveness was tested
decrement.
Rocky Mountain Power
Exhibit No. 1 Page 1 68 of 495
Case No. PAC-E-1+07
\Mrtness: Kathryn C. Hymas
using the 201I IRP 35%o east residential whole house load factor
Table 1: See-Ya-Later
Annual Program Costs
Table 2: See-Ya-Later
Savings by Measure Type
184,313
Table 3: IRP 3So/oLoad Factor Decrement
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0418 $96,489 $187,671 $91,182 1.945
Total Resource Cost Test ffRC) No Adder 0.0418 $96,489 $170,610 $74,121 1.768
Utility Cost Test ruCT)0.0464 $107,034 $170,610 $63,576 1.594
Rate lmpact Test (RlM)$294,767 $170,610 ($124,157)0.579
Participant Cost Test (PCT)$21,300 $369,026 $347,726 17.325
Lifecycle Revenue lmpacts ($/kwh)$0.000006024
Discounted Particioant Pavback (vears)0.22
Rocky Mountain Power
Exhibit No. 1 Page 1 69 of 495
Case No. PAC-E-14-07
Vwness: Kathryn C. Hymas
Low Income Weatherization - Schedule?L
The tables below present the cost-effbctiveness findings of the Idaho Low Income
Weatherization program based on Rocky Mountain Power's 201I costs and savings estimates.
The Utility discount rate is from the 201I Integrated Resource Plan (lRP).
Cost-effectiveness was tested using the 201I medium IRP 35% east residential whole house load
factor decrement. The results for a second scenario with reduced evaluation costs are also
presented below.
Table 1: Low Income Weatherization
Annual Program Costs
Table 2:
Annual Program
Low Income Weatherization
Costs - Reduced Data Request Costs
Table 3: Low Income Weatherization
Savings by Measure Type
Table 4: Low Income Weatherization
Total Resource Cost Test (PTRC) +
Conservation Adder 0.1 263 $253,809 $207,273 ($46,536)0.817
Total Resource Cost Test ffRC) No Adder 0.'t263 $253,809 $188,430 ($65,379)0.742
Utility Cost Test (UCI 0.1 263 $253,809 $188,430 ($65,379)0.742
Rate lmpact Test (RlM)$438,998 $188,430 ($250,568)0.429
Participant Cost Test (PCT)$0 $1 85,1 89 $1 85,1 89 N/A
Lifecvcle Revenue lmDacts ($/kwh)$0.0000053322
Discounted Particioant Pavback (vears)N/A
Rocky Mountain Power
Exhibit No. 1 Page 170 of495
Case No. PAC-E-1+07
Vlfitness: Kathryn C. Hymas
Table 5: Low Income Weatherization with Reduced Data Request Costs
Total Resource Cost Test (PTRC) +
Conservation Adder 0.1 078 $216,666 $207,273 ($9,393)0.957
Total Resource Cost Test (TRC) No Adder 0.1078 $216,666 $188,430 ($28,236)0.870
Utility Cost Test (UCT)0.1078 $216,666 $188,430 ($28,236)0.870
Rate lmpact Test (RlM)$401,855 $188,430 ($213,425)0.469
Particioant Cost Test (PCT)$0 $1 85,1 89 $185,189 N/A
Lifecycle Revenue lmpacts ($lkWttl $0.000004541 I
Discounted Particioant Pavback (years)N/A
r,n'ooX,""l?I"iTi?l:'"1'1
Case No. PAC-E-1tt-07
Wrtness: Kathryn C. Hymas
Energy FinAnswer - Schedule 125
The tables below present the cost-effectiveness findings of the Idaho Energy FinAnswer program
based on Rocky Mountain Power's 201I costs and savings estimates. The Utility discount rate is
from the 201I Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 201I IRP 69%o east system load factor decrement.
Table L: Energy FinAnswer
Annual Program Costs
Table 2: Energy FinAnswer
Savings by Measure Type
Table 3: IRP 69o/oLoad Factor Decrement
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0563 $197,570 $327,460 $129,891 1.657
Total Resource Cost Test ffRC) No Adder 0.0563 $197,570 $297,691 $100,122 1.507
Utilitv Cost Test (UCT)0.0440 $154,367 $297,691 $143,324 1.928
Rate lmoact Test (RlM)$347,371 $297,691 ($49,679)0.857
Participant Cost Test (PCT)$114,846 $300,270 $185,424 2.615
Lifecycle Revenue lmpacts ($/l(Wh)$0.0000013874
Discounted Particioant Pavback (vears)3.17
Rocky Mountain Power
Exhibit No. 1 Page 1 72 of 495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
FinAnswer Express - Schedule 115
The tables below present the cost-effectiveness findings of the Idaho FinAnswer Express
program based on Rocky Mountain Power's 2011 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2011 IRP 69%o east system load factor decrement.
Table la: FinAnswer Express
Annual Program Costs - RIM and UCT Perspectives
$1,311,514
$71,113
Table lb: FinAnswer Express
Annual Program Costs - PTRC, TRC, and PCT Perspectives
$574,913
Table 2a: FinAnswer Express
Savings by Measure Type - RIM and UCT Perspectives
Table 2b: FinAnswer Express
Savings by Measure Type - PTRC, TRC, and PCT Perspectives
10
Rocky Mountain Power
Exhibit No. 1 Page 173 of495
Case No. PAC-E-14-07
Vllrtness: Kathryn C. Hymas
Cost Effectiveness Inputs at the Measure Level
Rocky Mountain Power and Idaho Office of Energy Resources (OER) has an Energy Efficiency
Incentive Agreement in place for completion of public school projects. The Agreement provides
for a cooperative relationship to maximize the use of federal funding to promote and execute
additional cost effective energy efhciency measures in public schools within the Company's
territory. Because the participant costs reflected total project costs which included non
incentivized measures from the Company. All associated costs and energy savings from the
school programs were removed from cost effectiveness tests for PTRC, TRC and PCT
perspectives
Table 3: IRP 69o/oLoad Factor Decrement
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0816 $938,487 $1,102,393 $163,906 1.175
Total Resource Cost Test (TRC) No Adder 0.0816 $938,487 $1,002,175 $63,688 1.068
Utilitv Cost Test ruCI 0.0466 $700,723 $1,309,218 $608,495 1.868
Rate lmoact Test (RlM)$1,788,881 $1,309,2'18 ($4i9,664)0.732
Particioant Cost Test (PCT)$847,429 $1,376,046 $528,617 1.624
Lifecvcle Revenue lmoacts ($/kwh)$0.0000155022
Discounted Participant Payback (years)s.30
11
E-hi bittTY Y":Ti?i :'"ffJ
Case No. PAC-E-1+07
Vwness: Kathryn C. Hymas
Agricultural Energy Services (Irrigation Energy Savers) - Schedule 155
The tables below present the cost-efflectiveness findings of the Idaho Agriculture program based
on Rocky Mountain Power's 2011 costs and savings estimates. The Utility discount rate is from
the 2011 Integrated Resource Plan (lRP).
Cost-effectiveness was tested using the 2011 medium IP*P 20% east system commercial cooling
load factor decrement.
Table 1: Agriculture
Annual Program Costs
$172,796 $143,198
Table 2: Agriculture
Savings by Measure Type
Table 3: IRP 20oh Commercial Cooling Load Factor Decrement
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0757 $68'1,662 $941,267 $259,605 1.381
Total Resource Cost Test fiRC) No Adder 0,0757 $681,662 $855,697 $174,035 1.255
Utilitv Cost Test (UCT)0.054s $490,980 $855,697 $364,718 1.743
Rate lmoact Test (RlM)$951,431 $855,697 ($95,734)0.899
Particioant Cost Test (PCT)$565,404 $851,3s4 $285,950 1.506
Lifecycle Revenue lmpacts ($lkWnl $0.0000046450
Discounted Participant Pavback (years)2.82
12
Rocky Mountain Power
Exhibit No. 1 Page 175 of495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
YE8fi[XrJrouNrAIN
Exhibit No. 1.3
2012 Annual Report
Rocky Mountain Power
Exhibit No. 1 Page 176 of 495
Case No. PAC-E-1zl-07
Witness: Kathryn C. Hymas
Idaho Energy Efficiency and
Peak Reduction Annual
Report
January l, 2012 - December 31, 2012
Issued April 30,2013
ROCKY MOUNTAIN
POWER
Lett turn the onswers on.
Rocky Mountain Power
Exhibit No. 1 Page 17 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
(This page intentionally left blank)
Page2 of36
Rocky Mountain Power
Rocky Mountain Power
Exhibit No. 1 Page 1 78 of 495
Case No. PAC-E-14-07
Y{Btts8fluo%tUffisldaho Report
Taulu trF CoN'l'f,N1's
List of Abbreviations and Acronyms............. .........5
Executive Summary ............6
2012 Perforrnance ........... 8
Regulatory History...... ........9
Schedule 191. Customer Efficiency Services Rate Balancing Account Summary................... 10
Planning Process ...............12
Integrated Resource P1an........... ......12
Energy Efficiency Programs ...............14
Residential Programs ........14
Home Energy Saver Program.... ......14
Program Management............... ..................... 15
Program Administration............ .................... 15
Infrastructure ............. 16
Evaluation ..................20
Refrigerator Recycling .................... 20
Program Management............... .....................21
Program Administration............ .................... 2l
Infrastructure.............. .................22
Evaluation ..................22
Lorv Income Weatherizatton ...........22
Program Management............... ..................... 23
Program Adrninistration............ ....................23
Evaluation. .................24
Low Income Energy Conservation Education ....................24
Commercial and Industrial Programs................ .....................25
FinAnswer Express .......25
Program Management............... .....................26
Program Administration ............ ....................26
Infrastructure .............27
Evaluation ..................28
Agricultural Energy Services ..........28
Program Management............... .....................29
Page 3 of36
Rocky Mountain Power ldaho Report
Roclq Mountain Power
Exhibit No. 1 Page 1 79 of 495
Case No. PAC-E-1+07
f[BlE SPEUhtSmS
Program Administration............ ....................29
Infrastructure .............. ................. 30
Evaluation. .................30
Energy FinAnswer .........30
Program Management............... ..................... 3l
Infrastructure .............. .................32
Evaluation. .................32
Communications, Outreach and Education............. ................ 33
Earned Media ................33
Customer Communications ............. 33
Program Specific ...........33
Home Energy Saver program ......34
Residential Refrigerator Recycling ...............34
FinAnswer Express and Energy FinAnswer .................... 35
Agricultural Energy Services..... ....................35
Evaluations................ ........ 36
Page 4 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 80 of 495
Case No. PAC-E-1+07
f[BlgSfUo%tUfirs
CFLs
CAPAI
DSM
EICAP
EM&V
HVAC
IECC
IDHW
IRP
kwh
LEDs
MW
NAPEE
NTG
PCT
PTRC
RIM
Schedule
SEICAA
SYLR
TRC
UCT
Llsr or AtrgRtrt'larlon-s Ar{D AcRorriy}Is
Compact Fluorescent Lights
Community Action Partnership Association of Idaho
Demand-Side Management
Eastem Idaho Community Action Plan
Evaluation, Measurement & Verifi cation
Heating, venlilation and air conditioning
International Energy Conservation Code
Idaho Department of Health and Welfare
Integrated Resource Plan
Kilowatt hour
Light-emitting diodes
Megawatt
National Action Plan for Energy Efficiency
Net-to-Gross
Participant Cost Test
Total Resource Cost Test with l0 percent adder
Ratepayer Impact Measure Test
Customer Efficiency Services Rate Adjustment
SouthEastern Idaho Community Action Agency
See ya later, refrigerator@
Total Resource Cost Test
Utility Cost Test
Page 5 of36
Rocky Mountain Power
Exhibit No. 1 Page 181 of495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report E xUUIltirJS'S{Ilfi rfl 81S
Exrcurrl,E StrNr\.rARY
Rocky Mountain Power ("Company") working in partnership with its retail customers and with
the approval of the Idaho Public Utilities Commission ("Commission"). acquires energy
efficiency and peak reduction resources as cost-effective altematives to the acquisition of supply-
side resources. These resources assist the Company in effrciently addressing load grorvth and
contribute to the Company's ability to meet system peak requirements. Cornpany energy
efficiency and peak reduction programs provide participating Idaho customers with tools that
enable them to reduce or assist in the management of their energy usage while reducing the
overall costs to Rocky Mountain Power's customers. These resources are relied upon in resource
planning as a least cost altemative to supply-side resources.
This report provides details on program results, activities, expenditures, and Customer Efficiency
Service Charge - Schedule 191 ("Schedule 191") - revenue for the performance period from
January 1,2012, through December 31.2012. The Company, on behalf of its customers invested
$3.4 million in energy efficiency resource acquisitions during the reporting period. The
investrnent yielded approximately 12.6 gigawatt-hours in first year savingsland approximately
2.7 megawatts of capacity reduction from energy efficiency2. Net benefits to customers based on
the projected value of the energy efficiency program savings over the life of the individual
measures are estimated at $2.4 million3. The cost effectiveness of the portfolio including Low
Income Education savings from various perspectives is provided in Table 1.
Iable I -- l-ong-1enn C.ost l-.liiciiveness for the finergl' Lflicienc;- Port{blio
Benefit/Cost I Net BenefitsRatio i
I Total Resource Cost Test plus 10 percent ("PTRC") - total resource cost with
i the addition ofenvironmental and non-enerw benefitsl 1.36 $1,734,253
i Total Resource Cost Test ('TRC") - effects on both participants and non-1.23
-p3rtrclpglE1_Utiliw Cost Test ("UCT''l- effect on customerso
($2.23e.12)
1 Reported savings at generation.
2 See Appendix 1 for explanation on how the capaciry contribution savings values are calculated.
'' See Table 1 - Utilit-v Cost Test Net Benefits.o The TRC plus 10 percent includes a benefit adder to account for non-quantified environmental and non-energy
benefits ofconservation resources over supply side alternatives.t The TRC compares the total cost of a supply side resource to the total cost of energ,v efficiency resources,
including costs paid by the customer in excess of the program incentives. The test is used to determine if an energy
efficiency progftlm is cost effective from a total cost perspective.u The UCT compares the total cost incurred by the utilir-v to the benefits associated with displacing or deferring
supply side resources.
' The PCT compares the portion of the resource paid directly by participants to the savings realized by the
participants.t The RIM examines the impact of energv efficiency on utility rates. Unlike supply-side investments, energy
efficiency programs reduce energy sales. Reduced energy sales lowers revenues (see UCT) putting upward pressure
on rates as the remaining fixed costs are spread over fewer kilowatt-hours.
$2,4 r 3,I 352.43 i $4.244.173
Page 6 of36
Retailers
Roclry Mountain Power
Exhibit No. 1 Page 1 82 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report exWtlttd8$tfifir1ffi9
The portfolio was cost effective based on four of five standard cost effectiveness tests for the
reporting period. The ratepayer impact measure test was less than 1.0 indicating near-term
upward pressure was placed on the price per kilowatt-hour given a reduction in sales. Annual
performance information for 2012 cost effectiveness is provided in detail in Appendix 2.
h 2A12, the Company began development of a Technical Reference Library which contains
preliminary measure-level savings data, including the methods, assumptions and sources for
those assumptions used for reporting of energy savings. A preliminary Energy Efficiency
Measures report is provided in Appendix 3.
During the reporting period. the Company through its third party administratorse worked with the
following number of retailers. contractors, and vendors to support the energy efficiency
programs in Idaho:
T'able I - Energi E{1'lcir';rcr il-lliaslructr.rre
Residential
Retailers
Insulation Contractors
Window Contractors
Low Income
Comrnercial and Industrial .Lielr!!eJ$!_._AU!gs _ _i "1-4 iHVAC Trade Allies | 34 |
i Motors Trade Alliesi Enqineerinp Firms 24 ,I Engineering Firms , 24 r
Performance of the Idaho Irrigation Load Control programs is contained in Appendix 8.
n see program specific sections for backgrounds on third parry administrators.
"'Heating, ventilation and air conditioning
Page 7 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 183 of495
Case No. PAC-E-14-07
ExUUllttilS$&fiffi
2012 Pertbrrflunce
Program and Sector level results for 2012 are provided in Table 3 below.
'l'able 3
iciaho Progranr Resr:lts 1'or .Ianuar1, I . 2012 - f)eccmber 3 1, l0l2r r
Prosram
kWh/Yr
Savings
(at site)
kWh/Yr
Savings
(at penerator)
Program
Exoenditures
Low Income Weatherization (21 230.238 256.637 $ 284.549
Low lncome Education Program (21 20"536 22.891
Refriserator Recyclins (l 17)806 105 898.533 $ 102.878
Home Energy Saver ( 1 18)2.616.739 2,916,774 $ 652.248
Total Residential 3,673,618 4"094.835 $ 1"039.675
Enersv FinAnswer (125)C 0 $ 21,27s
FinAnswer Express ( I 1 5)2-205-353 2.442.406 $ s 32.7 tl
Total Commercial 2.205.353 2"442.406 $s53.986
Energy FinAnsrver ( I 25)318.9r 5 34?.904 $ t 38.323
FinAnswer Express ( I l5 )2.170.785 2,334,07 |$ 216.347
Total Industrial 2.489.700 2,676,975 $ 354,671
FinAnswer Express (l 15)96.974 r08.076 $ I 1,943
Agricultural Energy Services ( 1 55)2,954,136 3.292.325 $ 652.299
Total Asricultural 3.051.r 10 3,400,401 $ 664.241
Total Enerev Efficiencv 11,419,781 12,6t4.617 2.612,573
C&lEvaluationCosts
Residential Evaluation Costs
Technical Reference Library
New Programs
Total Svstem Benefit Expenditures - All Programs
$
$
$
$
$
696,359
r00.261
6,477
82
3,415,751
rr The values at generation include line losses between the customer site and the generation source. The company's
line losses by sector for 2012 are 11.47 percent for residential, 10.75 percent for commercial,7.52 percent for
industrial and 1 1.45 percent for irrigation.
Page 8 of36
Rocky Mountain Power
Exhibit No. 1 Page 184 of495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Rgg\fiei8sry?r,#u?T
RscularoRY HlsroRY
During the reporting period the Cornpany filed a number of compliance and/or informational
reports. updates and requests with the Commission in support of the Company programs. The
following is a list of those filings:
o February 22, 2012, the Company submitted its annual Demand-Side Management
("DSM") Balancing Account Review for 2011 to the Commission, pursuant to PAC-E-
05-1 0.
On April 30, the Company submitted its 201I Idaho Energy Efficiency and Peak
Reduction Annual Report. This report was revised on June 19, 2012 to address minor
corrections with participation count and appendix updates and again on August 3,2012to
address corrections on reported savings from a third party program administrator.
May 15.2012. the Company filed an applicationr2 with the Commission requesting an
order approving proposed revisions to FinAnswer Express - Schedule 115, and
requesting a change enabling the Company to manage the program outside the tariff and
make program changes through a flexible tariff. Changes were effective July 14.2A12.
o June 19,2012.the Company proposed
Program Schedule I l8 through
Commission and summarized in the
effect August 20.24n.
modifications to the Home Energy Saver Incentive
the flexible tariff approach approved by the
tariflf Provision of Service No. 5. Chanses took
o On December 7,2072, the Company requested authority to cancel schedules 72 and 72A,
and sought approval for a new lrrigation Load Control contractl'1.
On February 15,2102 the Commission directed Commission Staff ("Staff') to convene a public
workshop to explore in greater detail issues related to the funding and evaluation of utility Lou.,
Income Weatherization and Energ,v Conservation Education programs. The Company
participated in this workshop on March 19, 2012. On October n" 2A12 Staff prepared and
submitted a report of its findings and recommendations. The Company provided comments on
Staffs recommendations pursuant to tl-re Commission's November 12.2012 issue of a Notice of
Modified Procedures that set deadlines for interested parties to comment on.la
't Case PAC-E-12-10.
'' Changes took effect on March 8.2013 and will be reported on in the 2013 Idaho Energy Efficiency and Peak
Reduction Annual Report. Case PAC-E-12-14.
't The Commission issued Order No. 32788 for Case No. GNR-E-12-01 on April 12,2013. Recommendations that
would impact the cost effectiveness of Low Income Weatherization program were applied in this annual repor-t.
Page 9 of 36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 85 of 495
Case No. PAC-E-1+07
RUgffiat8l9lfrdttfiy
Schedule 191, Custamer Efficiency Senices Rute Balancing ,4ccount Swtnntary
In Case Number PAC-E-05-10 (Order 29976) the Commission approved the recovery of all
DSM program costs through Schedule 191, with exception of the expenses associated with the
irrigation load control program't. Schedule 191 charges appear as a line item on customer bills.
The Company books eligible DSM program costs as incurred to the balancing account.
On May 30,20l2"the Company filed an application with Case No. PAC-E-12-11 to decrease the
Schedule l9l, Customer Effrciency Services Rate, from 3.4 percent to 2.1 percent. The
Commission approved the Company's request with an effective date of August 1,2012.
Schedule 191 balancing account activity for 2012 is outlined in the Table 4 below.
'' The Commission, in Case No. PAC-E-10-07, ordered that the costs associated with the Idaho Irrigation Load
Control Program should be allocated as system costs and not situs to ldaho.
Page 10 of36
Rocky Mountain Power Idaho Report
Roclq Mountain Power
Exhibit No. 1 Page 1 86 of 495
Case No. PAC-E-14-07
RggE:et8l1ry[r,dffiT
Table -l
Scheeiulc i9i Balancing Accor-nti .{ciir il,r
Balance es ot 12131111State of Idaho
Sumrnary - Balancing Account
Monthty Program
Cost - Frxed
Assets
$
$
$
Q
$
$
$
$
$
$
$
$
January
February
hrlarch
April
lilay
June
July
Argust
lSeptember
I
Accrued Costs
$ 92,972
$ (60,023)
Rate Recovery
(392,090)
(35 5,1 73)
(336,51 5)
(306,1 99)
(4s2,268)
(708,661)
(904,683)
(687,181)
(406,554)
(257,381)
(216,413)
(221,886)
Carrying Charge
$
e
$
$
$
$
$
$
q
c
(
$
1,183,202
Cash Basb
Accumulated
Balance
897.41 9
764,123
666,214
563,623
478,598
47,329
(550.778)
(898.989)
(842,617)
(840,822)
(67 5,441)
(690,1 67)
1,564,182
Accrual Basis
Accumulated
Balance
1 ,371 ,372
1,'178.053
1,099.973
1 ,025,1 17
921,780
51 I,559
38,21 5
(31 2.399)
(399,716)
(488,709
(331,35
70,75
lOctober
lNorember
105,441
221.185
867 $
692 $
596 $
512 $
434 $
219 $
(210) $
(604) $
(725) $
(701 ) $
(632) $
(56e) $
238,010 $
203.097 $
19,830
27.735
366,808 $ (18,312)
277 ,173 $ 29,048
306,787 $ I 16,762
339,574 $ (2,402)
463,651 $ (143,689)
2s9,877 $ (90,788)
382,426 $ (8,024)
207,729 $ (24,675)
$
a
$
$
Q
$
o
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$December
2012 totals 3,371,757 $ (61,566) $(5,245,005) $(1211
Column Explanations:
Monthl.v Prosram Costs - Fixed Assets: Monthly expenditures for all energy- efficiency program activities.
Accrued Costs: Program costs iucurred during the period not yet posted.
Rate Recovery: Revenue collected through Schedule l9l.
Carrying Charge: Monthly "interest" charge based on "Accumulated Balance" of the account. The current
"interest rate" for the Accumulated Balance is I percent per year.
Cash Basis Accunrulated Balance: Current balance of the account - a runnitrg total of account activities. A
negative accumulative balance means cumulative revenue exceeds cumulative expenditures; positive
accumulative balance means cumulative expenditures exceed cumulative revenue.
Accrual Basis Accurnulative Balance: Curent balance of account including accrued costs.
At the beginning of 2012, the underfunded balance was approximately $1.564 million and
decreased by approxirnately $ I .935 million during the year to show an ending balance of $371
thousand overfunded which includes the accrued cost.
Page 1 I of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 87 of 495
Case No. PAC-E-1+07
wffitrnflgP?oryess
Plalxrrc Pnocpss
I ntegrated Resource FIun
The Company develops a biennial integrated resource plan ("lRP") as a means of balancing cost,
risk, uncertainty, supply reliability/deliverability and long-run public policy goals. The plan
presents a framework of future actions to ensure the Company continues to provide reliable,
reasonable-cost service with manageable risks to its customers. Energy efficiency and peak
management opportunities are incorporated into the plan based on their availability.
characteristics and costs.
Energy efficiency and peak management resources can be divided into four general classes based
on their relative characteristics. the classes are:
Class 1 DSM (Resources from fully dispatchable or scheduled firm capacity product
offeringsiprograms) - Capacity savings occur as a result of active Company control or
advanced scheduling. Once customers agree to participate, the timing and persistence of
the load reduction is involuntary on their part within the agreed limits and parameters.
Class 2 DSM (Resources from non-dispatchable, firm energy and capacilv product
ofr'erings/programs) - Sustainable energy and related capacity savings are achieved
through facilitation of technological advancements in equipment, appliances, lighting and
structures or sustainable verifiable changes in operating and maintenance practices" also
commonly referred to as energy efficiency resources.
Class 3 DSM (Resources from price responsive energy and capacity product
offerings/programs) - Short-duration energy and capacity savings from actions taken by
customers voluntarily based on pricing incentives or signal.
Class 4 DSM (Resources from energy efficiency education and non-incentive based
voluntary curtailment programs/communications pleas) Energy and/or capacity
reduetion typically achieved from voluntary actions taken by customers, to reduce costs
or benefit the environment through education, communication and/or public pleas.
As technical support for the IRP, a third-party analysis is conducted to estimate the magnitude.
timing and cost of alternative energy efficiency and peak management options.16 The main focus
of the study has been on resources with sufficient reliability characteristics that are anticipated to
be technically feasible and assumed achievable during the IRP's 2}-year planning horizon. The
estimated achievable energy efficiency potential identified in the 201I study for Idaho was 63
average megawatts or 18 percent of retail sales.lT By definition this was the energy efficiency
potential that may be achievable to acquire during the 20-year planning horizon if determined
least cost and cost-effective compared to supply-side altematives within the Company's
integrated resource planning process.
'uwww.pacificom.com
0l I-Stud,v.pdf. Table 52 on oage 49.
''Ibid.
Page 12 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 188 of495
Case No. PAC-E-I4-07
PttttdifliPP?orygBS
The achievable technical potential for Idaho by sector is shown in Table 5. The 20ll potential
study indicates that 5 percent of the achievable technical potential for the Company, excluding
oregonl8' is in Idaho'le 'r'arrrc
-i
201 I ldaho Lnergr, [':l]r'-:iencv Ael.riei,'ahle 'i'echnica] Prter:iiili hr: Sectur'
Sector
Average Megawatts in ]2030 l Percent ofRetail Sales I
i Resident ial 25%--tqv; '-"-*-1
lndustrial 73o/o
lrrigation 1A%
* Note there is an additional 0.,l aMW associated rvith street lights
Energy efticiency resources vary in their reliability, load reduction and persistence over time.
Based on the significant number of measures iderrtified in the potential study it is difficult to
incorporate each measure as a stand-a-lone resource in the IRP. To address this issue, energy
efficiency measures are bundled by their weighted-average load shape, lives and costs to reduce
the number of combinations to a more manageable number.
The evaluation of energy efficiency resources within the IRP is also informed by state specific
evaluation criteria. While all states generally use commonly accepted cost effectiveness tests,
some states require variations in calculating or prioritizing the tests.
o Washington and Oregon utilize the total resource cost but allow for consideration of non-
energ,v benefits and a 10 percent regionalconservation credit in the determination of cost
effectiveness.o Utah utilizes the utility cost test as the primary determination of cost effectiveness.
The Compan-v evaluates program implemer,tation cost effectiveness (both prospectively and
retrospectively) under a variation of five tests to identify the relative impact and/or value to
customers and the Company (i.e. near-term rate impact, program value to participants, etc.).
Both the 2008 and 201 I lntegrated Resource Plan preferred portfolios included the acquisition of
energy efficiency resources. The action plan targets for the 2008 and 201 I Integrated Resource
Plan updates'o u." shown iri Table 6.
I'airle (r
f.'rcfurre<.i ['trfi f oiilr L.ncrsr [:{'1lci*ncr'fi.!'s*ts
I 2008 Preferred Portfolio re 468 - 525 watt hours of effi 201 8
201 1 Prefened Portfolio Acquire a minimum of 5 I 7 average megawatt hours of energy efficiency
2020
18 Demand-side Management potential studies are performed by the Energy Trust of Oregon.
'' Page 49. Table 52 of the Assessment of Long-term, System-Wide Potential for Demand-Side and Other
Supplemental Resources.
2o 2008 IRP update, March. 2010. and 20l l IRP LC 52 Revised IRP Action Plan, January ,2012.
Page 13 of36
Rocky Mountain Power
Exhibit No. 1 Page 189 of495
Case No. PAC-E-14-07
Rocky Mountain Power ldaho Report R e slWBltti 6f 'HtEflJtrfs
Er u nc r" E I.rtcnix cl' PRoctrA,N{ s
Energy efficiency programs are offbred to all rnajor customer sectors: residential. commercial,
industrial and agricultural. The overall energy efficiency portfolio includes six programs: Honte
Energt Savings - Schedule 111, Residential Ref igerator Recycling- Schedule 117, Low Income
Weatherization - Schedule 118. Energt FinAnsv,er - Schedule 125, Agricttltural Energt
Serryices - Schedule 155 and FinAnswer Express - Schedule 115. Results for 2012 were
provided in Table 3.
RsstocxrrA L PRocrLdr\,rs
The residential energy efficiency portfolio is comprised of three programs, Home Energy Saver,
Residential Refrigerator Recycling and Low Income Weatherization. As shown in Table 10, the
residential portfolio was cost effective based on four of the five standard cost effectiveness tests
for the 2012 reporting period. The ratepayer impact test was less than I .0 indicating that there is
near term upward pressure placed on the price per kilowatt-hour given a reduction in sales.
'f ebie l(i
I.,onE-telnr ('ost L:l-iecriveness Ior l{esidentiarl []ort{aiicr
Benefit/Cost I Net Benefits IRatio i i
i&tal&esourcefestptustOp _ : 1.60 : $796,276i
i Total Resource Cost Test , 1.39 : $527,276 I
, Utilitv Cost Test s72s.002
, Participant Cost Test 081.289
I Rate 0.6s ($ l "300
I{ome Energ: Ssver Progr**t
The Home Energy Saver program is designed to provide access to and incentives for more
efficient products and services installed or received by customers in new or existing homes.
multi-family housing units or manufactured homes. Program participation by measure is
provided in Table I 1.
"l'ahle I I
n:l igi blc l'r*sranr N'leasr"u'i:s { l.l nils)
Central Air Conditioner Best Practice lnstallation
Central Air Conditioner Equipment
Central Air Conditioner Proper Sizing
Central Air Conditioner Tune-up
Gas Furnace with Electronically Commutated Motor
Electric System to Heat Pump Conversion
Page 14 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 190 of495
Case No. PAC-E-14-07
R e sl$Bitt i 5f Tryt!flJmrs
Measures
2012
Total
Units
Program performance results for the reporting period are provided in Table 12 below.
'l'airir' ll
J.()i-t!,*1erni {"'osl Iflb;li ver:ess iix" ] i*lx* L:nergr :al *r Fr$gi':-utl
Benefit/Cost , Nett'i _ ____ ..- *__-*tsetio__ _ BglefiE_ _ _
, Total Resource Cost Test plrs l0 per"ent
Total Resource Cost Test 1.66 $-s77.2 r8
Utiliry* Cost Test 2.22 $798.27 r
:js4lqjp3nt_c_g$_Te;I 2.98 $1.227.039
Rate Paver lmpact 0.74 ($518.096)
Program Management
The program n'Ianager is responsible for the Home Energ, Saver program and the Refrigerator
Recycling program in ldaho. California, Utah, Washington. and Wyoming. For each program
and in each state the program manager is responsible for the cost effectiveness of the prosram,
identif,iing and contracting with the program administrator through a competitive bid process.
establishing and monitoring program performance and compliance. and recommending changes
in the terms and conditions set out in the tariff.
Program Adrninistration
The l:lome line.rgX: Sat,er prograrn is administered by PECI (ft>rmerl-v the Pofiland Hnergl'
Conserrvatiorr. lnc.). PECI rvas incorporated b.v the Cif,v- 01'Portland. Oregon in 1979 to carr),olrt
private sector aspects ol'the Portland Energy'Conservation Policl,. In 1984 the Cornpany was
Electric Water Heater
Ceiling Fan
Light Fixture
Evaporative Cooler
Heat Pump, Ductless
lnsulation-Wall
Page l5 of36
Rocky Mountain Power ldaho Report
Rocky Mountain Power
Exhibit No. 1 Page 191 of495
Case No. PAC-E-14-07
ResY[gttti5fuHbEf,Jffis
spuu-otf from the Cir"'* of Portland. becomir,g a private. non-protit corporation. PECI has beerr
designing and implementing energy efficiency' programs since I990.
PECI is responsible for the follorving:
Retailer and trade ally engagement - PECI identifies. recruits, supports and assists
retailers to increase the sale of energv etficient lighting. appliances and electronics. PECI
enters into pronrotion agreernents rvith each lighting nranufacturer and retailer for the
promotion of discounted compact f'luorescent lighting ("CFL"). The agreen.rents include
specific retail lc'rcatiorrs. lightinq products receiving incentives and not-to-exceed annual
budgets. Weatherization and HVAC contractors engaged rvitl-r the prograln are provided
program materials. training and receive regular updates.
Inspections - PECI recruits and hires inspectors to veril)' on alr on-going basis the
installation 01'measures. Sumrnar,v of the inspection process is in Appenclix 4.
Incentive processing and call-center operatior-rs - PECI receives all reqLrests lbr
incentives. delennines rvlretlrer the applications are cclmpleted. rvorks clirectly rvith
customers lvhen infbrmation is incorrect andior missirrg fiom the application and
processes the application fbr paymerlt.
Program specific customer conrmunication and outreach A sunlmary o{' the
communicaticln and outreach conducted b1'PECI on lrehalf of the Cornpanv is outlined in
the Cornmunication. Or"rtreach and Education section.
Infrastructure
The Company' through its third part,v vendor is rvorking r.vith 2:l retailers to prornote CFLs and
light-enritting diodes 1"LliDs"). 'fable 13 Iists the lighting retailers participating in the program.
Tll.lc l-lll
I{etail Stcre.q - l-iehii:.}s
'' 'ro he considered
cuslomors must be a
fbr participation lbr discounted CFI",s
significant rna.|orit,v of total sales.
and l.EDs, sales coming frorn Rock,v Mountaiu l'ower
Page 16 of36
Ace Hardware #9179
BMC West - Rexburg
Broulim's Fresh Foods #l
I Broulim's Fresh Foods #2
I Broulim's Fresh Foods #3
Dollar Tree #-3691
Rocky Mourrtain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 92 of 495
Case No. PAC-E-14-07
ReslUBlttiSfWblfHtrfS
Store Name Citv
Familv Dollar #6349 Preston
Family Dollar #6398 Saint Anthony
Familv Dollar #6777 Rexburg
Familv Dollar #6790 Monpelier
Mickelsens #2 Rexburg
Platt Electric Supply #88 Rexburg
Thomas Market Inc. #l Malad City
True Value #10119 Preston
True Value #10217
Malad Cit"v
i True Value #5448
True Value Hardware - CAL Ranch Stores
: Walgreens #991 8
Walmart #1878
Wolfe Lighting
Over 40 local and national retailers now consistently promote high efficienc), appliatlces on
behalf of the program. Table 14 lists the retailers u.here customers can purchase progranl
qual i f1,ing app I i ances for trrrogram incenti v es.
'i'abli: l:l
I(eail Stores * Apriiances
!;()l
-l
l,/oH
>,i9^Ex.3J
!v /_O0/
^J
,L. (.1
q)::c)
.>qQ)
8 2 #
AAv!rLu. lti, Irl
E.
a0
q,)U
Ist Street Plumbing
Ace Hardware - Rexburg
: Best Buy #944
Bingham & Sons Furn. & Appl.
Blacker's Home Furnishings
, Blacker's Complete Home Furnishings
Blackfoot Appliance
: Brand Source
Dell's Home Appiiance and Mattress Center
I Idaho Falls
Idaho Falls
Idaho Falls
Dell's Mountain Electric
Page 17 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 193 of495
Case No. PAC-E-14-07
Re sl[Biiti 5f 'Hb}flJtrfS
Retailer
i Denning's Showcaseffi
, El Genes
Electrical Wholesale Supply Co Inc
I Elements Building Specialities lnc.
Falls Plumbing Supply, Inc
Ferguson Enterprices
, First Street Plumbing
Gundersen True Value
Home Depot #1802
#1807
Home Depot #1808
Lowe's of Idaho Falls
Lowe's of Pocatello
Northgate Appliance
Pocatello Electric CO.
RC Willey Appliances-Treasure Valley
Store
Rocknacks Hardware Plus
Sanders Furniture
Sears #l 060
I Sears #2109
I Sears#2278
Sears#3121
Sears #3192 - lnd/Blackfoot
Sears #3290 - Ind/Rexburg
Stronks & Sons Do It Best
Thomas Electric & Furniture
True Value - Gundersen True Value
U&IFurnitureCo.
Rexburg
Idaho Falls
Idaho Falls
Meridian
Idaho Falls
Montpelier
Idaho Falls
Chubbuck
Lewiston
Idaho Falls
Pocatello
Idaho Falls
Pocatello
Meridian
ldaho Falls
Soda Springs
Chubbuck
Twin Falls
I Blackfoot
i Rexburg
Ashton
i Malad
i Montpelier
I Preston
./i
li
7
/l
,/i
/1
,/l
Wolfe Lighting & Accents Rexburg
Page 18 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 94 of 495
Case No. PAC-E-1+07
ResltBtttiSf dHbEflJffiS
Table 15 and Table 16 list the HVACI" rveatherization and windorv conractors.
'l'al-rle 15
['lVAC Contraciors
Contractor Name
Holeshot Plumbing
Alpine Heating Idaho Falls '/ i '/ t, '/
Conan Heating
First Call Jewel. Inc
Palmer Heating and i,!Idaho Falls 1, ,/ | ,/ i /
rl.'Coolins LLC
: Quantam Group Idaho Falls I /./ l.t: Ensineerin
: Sermon Service and
, Electric
Malad Heating and MaladCity, / |Cooline LLC
Master Tech LLC
Sprinter Heating and Rigby
Young Electric, Heating
l and Air
o
(!
o
IJ
o(,
50
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50
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Idaho Falls l
IdahoFalls i t i t
Shelley I t
Page 19 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 95 of 495
Case No. PAC-E-14-07
ResYtBittiSf'HbEflJffiS
l-able l6
Weathrri zat ion Cr-lntraciors
I Precision Glass
I Rocky Mountain Insulation
Evaluation
In February 2012" a process and impact evaluation was completed by a third party evaluator for
program years 2009-2010. The impact evaluation provided data on the gross realized savings and
the Net-to-Gross ("NTG") ratio2:. The process evaluation investigated participant satisfaction,
implementation and delivery processes, marketing methods and quality assurance. The
Company's response to the recommendations and web link to the evaluation report are included
in Appendix 5.
R e.f?i g er ut o r R e cJ: c li n g
The Refrigerator Recycling program. also known as'oSee 1ta later, refrigerato@," is designed to
decrease electricity use through voluntary removal and recycling of inefficient refrigerators and
freezers. Participants receive a $30 incentive for each qualiffing refrigerator or freezer recycled
through the program and an energy-saving kit which includes two CFLs. a refiigerator
thermometer card, energ,v-savings educational materials, and information on other efficiency
programs relevant to residential customers. Program participation by measure is provided in
Table 17.
tt NTG is a factor representing net program savings divided by gross program savings that is applied to gross
program impacts. This ratio is most often calculated as NTG :1 - freeridership rate + spillover rate.
q
o
.>
o
a
o
E-
o
t
Contractor Name
Hallmark Exteriors
Eco lnsulation
Go Green lnsulation CaldwelI
Alpine Heating Idaho Falls
I BMC WeSt ldaho Falls
Campbell's Qual ity Exteriors Idaho Falls
First Call Jewel Idaho Falls
Page 20 of 36
Rocky Mountain Por.ver Idaho Report
Rocky Mountain Power
Exhibit No. 'l Page 196 of 495
Case No. PAC-E-14-07
ne sluBiiti 5?'FruEflxms
]'able I 7
[,li gib] c' Program Vlciisures ( Lj nits)
I Enerev Savines Kit
Program performance results for the reporting period are provided in the Table 18 below.
"l'ahle I I
l.,cing{.ern: {iost tr-:fibctiveness for Reli!ger*tor Rec1,ciing
I Ratio i i
'l'otal Resource Cost Test olus l0 percent | 2.87 $r48.53s
i Total Resource Cost Test sr 27.800
Utilitr Cost Test 2.02 r $104.473 'lpun-i.ipurtEo.tr.ri"*-------r--N-A-----I-$427.909:
Rate Payer Jmpact ($l 10.429)
In 20l2,morethan85"269 pounds of metal, 13,200 pounds of plastics. and 1.983 pounds of
tempered glass were recycled. In addition, the capture. recover),or destruction of more than 912
pounds of ozone depleting Chlorofluorocarbons (greenhouse gases) and Hydro fluorocarbons,
comnronly used in refrigerants and foam insulation equates to approximately 2,75A metric tons
of carbon dioxide.
Program Management
The program manager is responsible for the Refrigerator Recycling program and Home Energv-
Saver program in ldaho, Califomia, Utah, Washington. and Wyoming. For each program and in
each state the program marlager is responsible for the cost effectiveness of the program,
identifying and contracting with the program adrninistrator through a competitive bid process.
establishing and monitoring program performance and compliance, and recommerrding changes
in the terms and conditions set out in the tariff.
Prosram Adrninistration
The lleJrigerator Rec.vcliirg program is administered b-v JACO Environmental ("JACO"). JACO
started over 20 )-ears ago in Snohornish Count,v. north of Seattle. Washington, .IACO iras grorvn
to become one of the largest recyclers of lrouse-hold appliances in the United States. The
Conrpany' contracts rvith JACO to provide customer scheduling. pick-up, incentive processing
and rnarketing services for the See 1'a iater, refrigerator(La, prosraur.
23 Participants in SYLR program incur no costs.
Page 21 of36
Rocky Mountain Power
Exhibit No. 1 Page 1 97 of 495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report Re slWBliti 5f 'Ht!flJfl fs
JACIO also ensures that over 95 percent of the components and materials of the discarded
appliance are either rec,vcled tor beneficial r.rses or eliminated in an environmentally,' responsible
rval'. The rernaining 5 percent can then be productively used as "f)uff' to faciiitate the
decomposition o{' biodegradable landfil I material.
JACO Environmental is responsible fbr the fbllorving:
Clustonrer and fleld senices *.|ACO handles all customer and field service operations for
the prograrn. Pick-Lrp of reti'igeratols and freezers from customers and transportin-e the
units to the de-manufacturing facility is done by .IACO.
Incentive processing and call-center operations - All customer selice calls. pick-up
scheduling and incenlive processing are handled hy JAC0.
Program specific customer cr:mmunicalion and outreach -- Working in close coordinatic'rn
rvith the Company,'" .IACO handles all the marketing tor the program. The program is
marketed through bill inserts, custorner nervsletters and TV, newspaper and oriline
advertising.
Independent third party contract inspectors are ernployed by the Compariy to ensure JACO's
performance. The summar) of the inspection process is included in Appendix 4.
Infrastructure
A crew from Salt Lake Cit."". Utah picks-up units in Idaho and trucks the units to a JACO facility
in Salt Lake City for disassembly and recycling.
Evaluation
In February 2012, a process and impact evaluation was completed by a third parfy evaluator for
program years 2009-2010. The impact evaluation provided data on the gross realized savings and
the NTC ratio. The process evaluation investigated participant satisfaction, implementation and
delivery processes, marketing methods and qualiqv assurance. The Company's response to the
recommendations and web link to the evaluation report are included in Appendix 5.
L0 n, I tt c:o m e lX' e u t lte ri latiott
The Low Inconte Weatherization program provides energy efficiency services through a
partnership between Rocky Mountain Por.ver and local non-profit agencies to income-eligible
households. Services are at no cost to the program participants.
Program participation and number of homes receiving specific measures is provided in Table 19.
Table tr t)
I'-lonrcs li ecei ving Speci lic \4easLrres
Particioation - Total number of Homes Served 104
Ceilins Insulation 50
Attic Ventilation JJ
Page 22 of 36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 1 98 of 495
Case No. PAC-E-14-07
ResYUBiitiSf'HtlflJffis
Program performance results for 2012 are provided in the Table 20.
Floor Insulation 26
Wall lnsulation 6
Water Pioe Insulation 8_s
Water Heater Repair I
Water Heater Replacement 4
Furnace Reoair 46
Furnace Replacements 2
Duct Insulation l3
Renlacement Windows 47
Infiltration 59
Thermal Doors 45
Refriqerators
Compact Fluorescent Lisht Bulbs 87
Health & Safetv Measures 64
'l'alrle l0
[-.onc-lerm i.os", i-{lectil'eness icr l.ou, lncomc \\'catire rization
Benefit/Cost
Ratio
I Total Resource Cost l-est plus 10 percent lI Total Resource Cost l-est plus 10 percent L 1.06 ; $16.808
I Ne1
i Benel'its
I __I9!43e!9!rce Co*st 1'est
I I ltilih. /-ncf Tect
l.\ru ! Qlu.ouo
1__,-0 7!, ___r $8i,521)
s4r8.r78
I Rale Payel Impact 0.42 ($275.463 )
Program Management
The program manager is responsible for the Low Income Weatherization program in ldaho,
Caiifornia, Utah, Washington and Wyoming: energy assistance programs in Idaho. California.
Oregon, Utah, Washington and Wyoming; and bill discount programs in Califomia, Utah and
Washington. The program manager is responsible for the cost effectiveness of the rveatherization
program in each state, partnerships and agreements in place with local agencies that serue
income eligible households. establishing and monitoring program perlormance and compliance,
and recommending changes in the terms and conditions set out in the agency contracts and state
specific tariffs.
Pro gram Administration
Rocky Mountain Power cumently has contracts in place with Eastern Idaho Community Action
Partnership ("EICAP") and SouthEastern ldaho Community Action Agency ("SEICAA") to
provide services through the low income weatherization program. These two agencies receive
federal funds allocated to the ldaho Department of Health and Welfare ("IDHW") and
administered by the Community Action Partnership Association of Idaho ("CAPAI") through
subcontracting non-profit agencies. Energy efficiency measures are installed in tlre homes of
income eligible households throughout the Rocky Mountain Power's service area by EICAP and
Page 23 of36
Rocky Mountain Power
Exhibit No. 1 Page 1 99 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report ResYEBlttiSf 'HtEflJnfS
SEICAA. Company funding of 85 percent of the cost of approved measures is leveraged by the
agencies w.ith the funding received by IDHW.
By contract with the Company, EICAP and SEICAA are responsible for the following:
a
a
Income Verification - Agencies determine participants are income eligible based on
CAPAI guidelines. Household's interested in obtaining weatherization services apply
through the agencies. The current income guidelines are included in Appendix 6.
Energy Audit - Agencies use a United States Department of Energy approved audit tool
to determine the cost effective measures to install in the participant's homes (audit results
must indicate a savings to investment ratio of 1.0 or greater).
Installation of Measures - Agencies install the energy effrciency measures.
Post lnspections - Agencies inspect 100 percent of completed homes. IDHW and
CAPAI also inspect a random sample of homes. See Appendix 4 for verification
summary.
Billing Notification - Agencies are required to submit a billing to Company within 120
days after job completion. The agencies include a form indicating the measures installed
and associated cost on each completed home along with their invoice.
Evaluation
A Request for Proposal will be issued during the third quarter of 2013 to perform Low Income
Weatherization process and impact evaluations.
Low lrrcottte Etrergy Conse*,ution Etlucatiort
The Low Income Energt Consert,ation Educatior program is designed to provide group and
individual in-home education sessions to qualif,ing parlicipants, as well energy efficiency
instant savings kits with easy to install measures. The energy efficiency kits include one 13 watt
CFL, one 19 watt CFL, one 23 watt CFL, ten electrical outlet insulation gaskets, one low flow
kitchen aerator, one refrigerator temperature card and one low wattage luminescent night light.
The kits compliment the education sessions which the agencies began offering in May. 2011.
A total of 151 households completed the conservation education sessions and received kits in
2012 resulting in a total estimated first year energy savings of 20,536 kWh at site. The program
was designed to reach 500 households with its original funding of $50,000 in 2010 and 201 l. As
of December 31. 201?, a total of 319 households have been served. No additional funds were
issued in2012.
Page 24 of 36
Rocky Mountain Power
Exhibit No. 1 Page 200 of 495
Case No- PAC-E-14-07
Rocky Mountain Power Idaho Report commerci at and I nwtlsfli 5f 'p{btflJflfs
Ccl narr n ncl AI- An n IliB Ll sT" R rAL FRoc;u,trt s
The commercial and industrial energy efficiency portfolio is comprised of three programs.
FinAnswer Express, Agrictrltural Energy Sen'ices and Energt FinAnswer. The commercial and
industrial portfolio was cost effective based on four of the five standard cost effectiveness tests
for tlre 2012 reporting period, as provided in Table 2l belo'iv.
I-o:rg-Lullu
'I..h1.. 11
i:l tlbc ti verress i nr {lor:rrrerc ial ancl I n,..1 ustria} Pqrrl fi: I i c
Net Benefits
Total Resource Cost Test
r-Ba!9-lgv-91 lr!g?!!($r.228.254)
f in.4rc s w e r' 6.r7:rc.r.s
The FinAnsw'er Express program is designed to assist commercial and industrial, customers
improve the efficiency of their new or replacement lighting, HVAC. motors, building envelope,
and other equipment by providing prescriptive or pre-defined incentives for the most common
efficiency measures listed in the program incentive tables.2a TIre program also includes custom
incentives and technical analysis services for measures not listed in the program incentive tables
that improve electric energy efficiency. The program provides incentives for both new
construction and retrofit projects, and is designed to operate in conjunction rvith the Energ;-
Fin-Answer program. Program participation by measure group is provided in Table 22.
i zirl.' ll
Li*:'isuies l iiirpi;calion: ;
Food Services
2a lncentive tables can be found online at http:/iwu,ui.rock-vmouutainpower.lletibusiseiepi//idahoiilclfe2.html for
retrofits and lrttp:iiwrvrv.r'ock)'mountainporver.netlbusrser epi: idahoinfinr,'f'e.htnrl for new construction/major
renovation projects
BenefiUCost
Ratio
t.28 $944,536
2012 Total
Proqram Total
Page 25 of 36
Rocky Mountain Power
Exhibit No. 1 Page 201 of 495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report Commerci al and I nUtlsff i SftHtlllJtrf8
Program savings by measure group is provided in Table 23.
"l'ahle 23
lnstallecl Prosram \4c'asures (gross k\lihll'ear at sitei
Program performance results for 2012 are provided in Table 24 below.
'l able 24
i.ont-teir"u C osr iitftctir,*ncss, irlr FinAnsn.er !;"xpress
BenefiVCost I Net Benefits
Ratio l
Utilin Cost Test 3.37 $r.806.263
I Participant Cost Test _ : 1.76 I $L_U9J2) ,Inat. p">,.. trrp"ct
-
orq8 l-G6o3z) i
Program Manaqement
The program manager is responsible for the FinAnsw,er Express program in Idaho. California.
Utah, Waslrington and Wyoming and the Agricultural Energl, Sen,ices program in Idaho. For
each state the program manager is responsible for the cost effectiveness of the program,
identifying and contracting with the program administrators through a competitive bid process,
program marketing, establishing and monitorirrg program performance and compliance, and
recommending changes in the tenns and conditions of the program.
Program Admi nistration
The program is primarily marketed through local trade allies who receive support from one of
two program administrators. The Company contracts with Nexant, Inc. ('Nexant") and Cascade
Energy ("Cascade") for trade ally coordination, training and application processing services fbr
commercial measures and industrialiagricultural measures respectivell,.
Nexant services include design. implementation, and evaluation of commercial. industrial, and
residential energy efficiency programs in the United States. The Company contracts with Nexant
2012Total
131.654
, Lighting _ i 4.216,144 i
i Motors I 1.009 i
sl,l78,_s89
I Total Resource Cost Test
Page 26 of 36
Rocky Mountain Power
Exhibit No. 1 Page 202 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Commercial and lrrW[lStfiSf'HblfUtrf8
to provide trade ally coordination and application processing services for the commercial
measures in the FinAnswer Express program.
Cascade is an industrial energy efficiency consulting firm providing both retrofit and new
construction capital studies; tune-ups and retro-commissioning; utility dernand-side management
program design and administration: research and development: and energy management services.
The Company contracts rvith Cascade Energy to provide trade ally coordination and application
processing services for the industrial and farm/dairy measures in the FinAnswer Express
progmm.
Nexant and Cascade are responsible for the following:
Trade ally engagement - Nexant and Cascade identifli, recruit, train. support and assist
trade allies to increase sales and installation of energy efficient equipment at qualif,ing
business customer facilities.
Incentive processing and administrative support - Nexant and Cascade handle incoming
inquiries as assigned. process FinAnswer Express incentive applications, develop and
maintain simplified analysis tools and provide program design services, evaluation and
regulatory support upon request.o Inspections - Nexant and Cascade verify on an on-going basis the installation of
measures. Summary of the inspection process is in Appendix 4.
ln addition. the Company's project managers coordinate FinAnswer Express projects and
provide customers with program services and incentives usir-rg the energy engineerirrg
consultants described further in the Energy FinAnswer program section.
Infrastructure
To help increase and improve the supplier and installation contractor infrastructure for energy-
efficient equipment and services. the Company established and developed trade ally netw'orks for
lighting. HVAC and motors. This u,ork includes identifying and recruiting trade allies, providing
program and technical training and providing sales support on an ongoing basis. The current list
of the trade allies who have applied and been approved as participating vendors are posted on the
Compan5, website and included as Appendix 7 to this report. Customers are not required to select
a vendor fronr this Iist to reoeive an incentive.
The total number of participating trade allies is currently" 78. The current counts of parlicipating
trade allies b1' teci.rnolo-q,v are in the Table 25.
Page27 of36
Rocky Mountain Power
Exhibit No. 1 Page 203 of 495
Case No. PAC-E-1+o7
Rocky Mountain Power Idaho Report commerci al and I nutlsff i 5f tryt!flJfl?s
Table l5
Par-ticipating Trade Aliies
Lighting a'ade allies
Evaluation
As of the end of 2012. a process and impact
underway. Results are expected to be available in
.4 gri utku ru I En erg; S e n ie' e s
evaluation for program years 2009-2011 was
May 2013.
HVAC trade allies i
I
l
Motor and VFD
trade allies
The Agriatltural Energ,, Sentices program is designed to improve the overall energy efficiency
of irrigation systems by promoting energy efficient irrigation practices and the installation of
energy efficient measures. The program also complements the Irrigation Load Control program
by focusing on improving the efficiency and management of these seasonal loads.
The 2012 program included the follow customer service and measure components:
Equipment Exchange: Provides new standard brass sprinkler nozzles, gaskets, and drains
to replace worn equipment on hand lines, wheel lines and solid set sprinklers systems.
Pivot and linear equipment Upgrades: Incentives are provided for certain pivot and linear
system measures including sprinkler packages, pressure regulators, and drains. The list of
prescriptive incentives is not designed to be exhaustive and other pivot measures are
eligible for incentives if energy savings can be calculated and the customer incurs costs to
make the changes.
System consultation: This senice provides a simple site specific audit of a customer's
irrigation system to promote irrigation water management and identifu 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
demand, and system pressures and is performed after the pump has been screened and the
ou,ner's financial investment criteria understood. System Analysis - The program
provides energy engineering to help growers quantify the costs and savings of their
system efficiency upgrades. Often these upgrade decisions are made in conjunction with
operational production change considerations impacting a growers equipment needs.
Incentives are based on a standard formula tied to costs and first year energy savings.
A summary of the program savings by measure group for 2012 is provided in Table 26.
t' Some trade allies may participate in more than one technology so the count of unique participating firms is less
than the total count by technology.
List dated 4;312013
Page 28 of36
Roclry Mountain Power
Exhibit No. 1 Page 204 of 495
Case No. PAC-E-14-07
Rocky Mountain Power ldaho Reporl Commercial and InWtISffi SfHbtflJtrfs
Tai,}r.']t-r
iils*rliecl }]r'.rgraln 14eo"s*res {grclss k* h,i} tr}^ rl- rltrr}
?q,Plq!41_l
302.15 1 l
i Pivot/Linear U
Redesi
Program performance results fbr the reporting period is provided inTable 27 .
^-'.i ahi': , -
L*na*ter;.yr {.*st l-ii*ciirreness itrr Agrie*;;,n';ri j n':rur 5,*'l'r iurs
Benefit/Cost
Ratio I Net Benefits
Total Resource Test plus I 0 percent 1.48 $421.667 i
Total Resource Cost Test 1.34 $304.868
,,Utillq,v_-c,q!I:!!J i l.($545.6961.84
; Participant Cost Test 2.24 $830.635 I
*Bqe-tgysllrypqsl- --- -- - --!-- i.z!---:--$1ZZa6-qL
Proqram Management
The program manager is responsible for the Agriculttrctl Energy- Services program in Idaho; the
FinAnswer Express program in ldaho, Califiomia. Utah" Washington, and Wyoming. For each
program and in each state the program manager is responsible for the cost effectiveness of the
program. identifying and contracting with the program adn'rinistrators through a conrpetitive bid
process, program marketing, establishing and monitoring program perfbnnance and compliance,
and recommending changes in the terms and conditions set out in the tariff.
Pro gram Administration
The program is primarily marketed through irrigation speciaiists, trade allies and retailers serving
local irrigators. These ef'forts are supported by the program administrator, Nexant.
The Company contracts with Nexant to provide trade ally coordination and application
processing sen ices for Agricu.ltural Energy Sat,ers program. Nexant is responsible for the
following:
o Trade ally engagement: identil-v. recruit, train, support and assist trade allies to increase
sales and installation of energy efficient equipment at qualifoing customer site.
1.492.563 l
1.t59.422 l
26 Results are based on planning assumptions regarding reponed savings.
Page 29 of36
Rocky Mountain Power
Exhibit No. 1 Page 205 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Commercial and InUtfffli 5f'HtltlJtrfS
Incentive processing and administrative support: handle incoming inquiries as assigned,
process incentive applications and provide program design services, evaluation and
regulatory support upon request.
Inspections: verify equipment installation on a sample basis for Equipment Exchange and
every installation for System Analysis.e Engineering analysis - provide site specific engineering as required by the program for
System Analysis.
Infrastructure
To help increase and improve the supplier and installation contractor infrastructure for energy-
efficient equipment and services, the Company developed trade ally networks for irrigation
equipment. The current lists of the trade allies who are participating vendors are posted on the
Company website2T.
Evaluation
As of the end of 2012, a process and impact evaluation for program years 2009-201I was
underway by a third party evaluator.
Energ; Fitt4ttsx,er
The Energy FinAnsw,er program is offered to all non-residential neu, construction, retrofit
commercial (buildings 20,000 square feet and larger) and industrial customers. The program is
designed to target comprehensive projects requiring project specific energy savings analysis and
operates in concert with the more streamlined FinAnswer Express program. The program
provides Company-funded energy engineering. incentives of S0.12 per kilowatt hour ("kwh")
for 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. In addition to customer incentives, the program provides
design team honorariums (a finder fee for new construction projects) and design team incentives
for new construction projects exceeding Intemational Energy Conservation Code ("IECC") 2009
energy code by at least l0 percent.
Projects completed during 2012 are provided in Table 28.
'l'able 28
Prrijecis ( timprleted
Itttp://www.rockymountainpower.net/content/dam/rocky_mountain3ower/doc/Business/Save_Energy_Money/lrrig
ation_Energy_Savers_Partic ipating_Dealers.pdf
FinAnswer Commercial
FinAnswer lndustrial
Page 30 of36
Rocky Mountain Power
Exhibit No. 1 Page 206 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Co m merci at and l nWtISff i Sf tPItSf,JflfS
Program savings by measure group is provided in Table 29.
"l'nhle 29
lnstallecl llr<igrarn \,'lessures (tross k\\rhrlerr ax site)
Totals
Program performance results for the reporting period is provided in Table 30 below.
'Tablc 3li
l-txrg-iet'n: {'ost It'{'ectivcuess lirl irrrergr l::iitAnswer
Benefit/Cost i Net
Ratio I Benefits
i Total Resource Cost Test plus l0 percent , 1.21 !i37.638 I
Total Resource Cost Test l.l() I S17.769 ,
I Lltilit"v- Cost Test : 1.25 i $39.091 |
, Participant Cost Test 3. I 8 , $ I 33.054 ,
I Rate Pa)'er Impact 0.69 I ($ti8.155) ,
Energl, FinAnsw,er program is administered b,v the Company'. Consequently" the program
mallager is responsible for the following:
Program cost effectiveness and performance
Ensuring the program is operated in compliance with commission tariffs and Companl,'
guidelines including but not Iimited to qualification of customers
Customer communication and outreach
Monitoring code and standard changes
Qualification of materials and equipment
Engineering analysi s of c ustomer opportunities
Qualitv control and assurance
Customer service, including the delivery of services and incentive
28 Based on the volume of projects, temporary project managers and/or support staff are employed from time-to-time
Program Management
The program manager is responsible for the Energy FinAnsw'er program in ldaho, Califonria.
Utah, Washington. and Wyoming; the Se{f-Direct progroru in Utah and Wyoming: and the
Comntercial & Industrial Re-Comntissioning program in Utah. The Companv employs four full-
time project managers2S in support of the pro-sram manager.
a
a
a
o
o
a
a
a
i
i Compr
i uvec
Measure 2012Total I
150.293
12"401
r Motors 156.221
318,915
Page 31 of36
Rocky Mountain Power
Exhibit No. I Page 207 ol 495
Case No. PAC-E-1+07
Rocky Mountain Por.ver Idaho Report Commercial and hWtIStliSf'Ht?*UtrfS
o Verification of installation and savings2e
Infrastructure
Given the diversity of the commercial and industrial custorners served by the Company, a pre-
approved, pre-contracted group of engineering firms are used to perform facility specific energy
efficiency analysis, quality assurance and verification. This being said, the individual projects are
directly managed by one of the Company's project managers. The project manager works
directly with the customer or through the appropriate community and customer account manager
located in Idaho. Table 3l lists the engineering firms currently under contract with the Company.
'l able 3 tr
I-:nuineerinc Finns
Ensineer Main Office Location
Abacus Resource Man OR
BacGen Technolosies Seattle, WA
Brendle Grouo Inc Fort Collins. CO
Cascade Cedar Hills. UT
I Compression Engineering Corp Salt Lake City. UT l
i Eaton - EMC Ensineers i Salt Lake City. UT l
EMP2Inc I Richland. WA
ETC G Salt Lake Ciry*, UT
Beaverton. OR
Milton-Freewater. OR
i Portland- OR
I Croqp l{ Etreing,e_rilg
i CSaS Architects
m
Salt Lake Citv. UT
I Interface Enqineeri Portland. OR
I kW Engineering lnc *ee!ler4.-c3
I PAE Consulting Engineers Inc i Portland, OR
r Nexant Inc i Salt Lake Ciry, UT
PCD En-eineering Services Irrc i Lonemont. CO*Qellrygy_lvtegsglr94"&9 _Lp Jey_e1tst,_qB
SBW Consultinq lnc I Bellevue. WA
Enersv Solutions Inc i Ashland, OR
I Solarc Architecture & Engineering lnc i Eugene, OR i
I Van Boerum & Frank Associates i Salt Lake City, UT I
Evaluation
As of the end of 2012, a process and impact evaluation for program years 2009-2011
underway by a third party evaluator.
Firm
Com
I RHT Energy Solutions i Medford, OR
,
2n Summarv of inspection process is in Appendix 4.
Page 32 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 208 of 495
Case No. PAC-E-1+07wiedhllltlt{tftdttts1i
Coltu t:xICATIoNs, OurRr.c.clr AND Enucartox
The Company utilizes earned media, customer communications, paid media and program
specific rnedia in an effort to communicate the value of energy efficiency. provide information
regarding low-cost. no-cost energy efficiency measures, and to educate customers on the
availability of technical assistance, services and incentives. The overall goal is to engage
customers in reducing their energy usage through behavioral changes as well as changes in
equipment, appliances and structures.
E*nted Media
Earned media is managed by Rocky Mountain Power's external communications department in
cooperation with the customer and community managers located in Idaho. "Earned media"
generally ref'ers to favorable television, radio, newspaper or internet news coverage gained
through press releases. media events" opinion pieces, story pitches or other communication u,ith
news editors and reporters. From January 1,2012 - December 31,2072, the Company identified
three news stories that mentioned its energy effrciency programs or tips which resulted from (l)
earned media activities, (2) articles placed in neu,spapers' progress editions in conjunction with
paid advertisements, and (3) without prompting by the Company. A list of the news stories" date
of publication or airing, and media outlet are listed below.
. 5l15 - Local News 8; KIDK 3 (television): Celebrating 100 years (energy efficienc,v
presentation at Ammon Elementary School to kick off Centennial Road Tour)o 5124 - The Idaho Enterprise: Elementary students visited by 'Slim the Lineman"o 5/23 - Montpelier News-Examiner: RMP celebrates 100 years of service
t' u s t o mc r C o n*n un i c atio x s
As part of the Company's regular communications to its customers, newsletters across all
customer classes promote energy efficiency initiatives and case studies on a regular basis. Inserts
and outer envelopes featuring energy efficiency messages and programs have also been used on a
consistent basis. ln2012, the Company also issued two newsleffers focused entirely on seasonal
energy efficiency information targeted in the fall and spring.
The Company also utilizes social media, such as Twitter and Facebook to communicate and
engage customers on DSM offers and incentives.
Progrum Spectfic
All energy efficiency program marketing and communications are under the wattsmart umbrella
to ensure a seamless transition from changing customer behavior to the actions they could take
by participating in specific programs. Separate marketing activities administered by and specific
to the programs ran in conjunction with the wattsmart campaign.
Page 33 of36
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. I Page 209 of 495
Case No. PAC-E-1+07wu6h{l?[utr8dtrtsli
Home Energy Saver program
The Home Energt Saver program communicates to customers. retailers and trade allies through a
variety of channels. In January and February 2012, new heat pump sales pieces were developed
and a retailer resource manual was distributed. Communications promoting online application
processing were provided to retailers during the first part of the year as well.
In the summer, program communications focused on cooling measures. The cooling campaign
included:
. Room air conditioner point of purchase materialo Handout material for retailers and trade allies to use in their sales to customers. Web features
. Online and print adso Bill insert
Results from the campaign indicate increased savings from cooling measures in 2012 compared
to previous years.
A similar heating campaign was developed for the fall and winter, including:. Web features. Sales handout and outreach to trade allieso Bill insert. Social media
Results from the campaign will be compiled after the heating season in 2013.
ln November 2012, the Company launched a Black Friday campaign to promote efficient
equipment purchases during the holiday shopping season and encourage participation in the
program.
Residential Refri gerator Recycl ine
The Company promotes its See ya later, refrigerator@ program through informational
advertisements and other customer communications. In 2012, the program gamered 1,287.684
impressions. Breakdor.rm of impressions by media type is shown in Table 32.
Tahle 32
See 3'a laler. reliigeralor,S) Progrant
Communications Channel 2012
Newsoaoer 1.27s.350
Dieital 12.334
Page 34 of36
Rocky Mourrtain Power Idaho Repo(
Rocky Mountain Power
Exhibit No. 1 Page 210 of495
Case No. PAC-E-14-,7*tr8tr{1fllxl8dtttsli
FinAnswer Exnress and Ener:g.y FinAnsrver
During 2012 communications emphasized the change in federal lightin-g standards that took
place .luly 14,2012. This standard applies to manufacturers of general service fluorescent lamps.
Customers were encouraged to retrofit their older linear fluorescent lighting before as well as
after the standards change. The Company added a video3O and retained a page3l on the website
dedicated to this topic. ln 2012, the program gamered 493,098 impressions. Breakdown of
impressions by media type is shown in Table 33.
T;h,ic il
l,rre ll_r I irt tit:rr.'r'lrrtl i:i:t \l'irr.; I \ilrL':s p:'1 .Iitr jl:
Asricultural Energ), Services
The Company promote s the Agricultural Energy Sen ices program at key events and reaches out
directly to participating customers and dealers when there are updates or changes to the program.
Communication activities during 201 2 included:
irrigation Equipment Shou', presented by the Idaho Irrigation Equipment Association on
January 5,2012 in Idaho Falls, Idaho. The Company presented information about the
program and highlighted irrigation energy saving projects.
Eastem Idaho Ag Expo on January l7th, 18th, and l gth in Pocatello, ID. Company had
sponsored a booth to promote the program and answer program questions for customers
and dealers.
The update d 2012 program applications were provided to all of the participating dealers.
The Cornpany followed up with phone calls to ansrver any questions customers had
regarding the changes.
r..rock rrtai n norver,neti i dsavej1 wrvrv.rock]'rnountainoower'.nel,'li ghtingstandards
Page 35 of36
Rocky Mountain Power Idaho Report
Roclry Mountain Power
Exhibit No. 1 Page 21 1 of 495
Case No. PAC-E-1+07
wtness: Fpfllgfiulfs
E\r"tLtl,trIoNS
Evaluations are performed by independent extemal evaluators to validate energy and demand
savings derived from the Company's energy efficiency programs. lndustry best practices are
adopted by the Company with regards to principles of operation, methodologies, evaluation
methods, definitions of terms, and protocols including those outlined in the National Action Plan
for Energy Efficiency ('NAPEE") Program Impact Evaluation and the California Evaluation
Framework guides.
A component of the overall evaluation efforts is aimed at the reasonable verification of
installations of energy efficient measures and associated documentation through review of
documentation, surveys and/or ongoing onsite inspections.
Verification of the potential to achieve savings involves regular inspection and commissioning of
equipment. The Company engages in programmatic verification activities, including inspections,
quality assurance reviews, and tracking checks and balances as part of routine program
implementation and may rely upon these practices in the verification of installation information
for the purposes of savings verifications in advance of more formal impact evaluation results.
Evaluation. measurement and verification ("EM&V") tasks are segregated within the Company's
organization to ensure they are performed and managed by personnel who have a neutral interest
in the benefits associated with anticipated savings.
In June 2011, Rocky Mountain Power awarded
energy efficiency programs for all states. The
competitive bid process.
multi-year contracts to evaluate the Company's
contracts awarded were completed through a
The Idaho Home Energy Saver and See ya lctter, refrigerator@ program evaluations summary of
recommendations and web link to reports are provided in Appendix 5.
Outlined below is a list of the programs, the program years completed during 2012 and the third
party evaluator who performed the evaluation.
a later. refri 2009-2010 The Cadnrus
Years Evaluated
: 2009-2010 i The Cadmus
Page 36 of36
Rocky Mountain Power
Exhibit No. 1 Page 212 ol 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
Appendix 1
Explanation of Capacibr Estimates
20t2
Rocky Mountain Power
Exhibit No. 1 Page 213 of495
Case No. PAC-E-14-07
Vlfrtness: Kathryn C. Hymas
The MW reported savings of 2.69 (at generation) for energy efficiency programs during 2012
represents the summation of estimated MW values made available through the Company's
business and residential energy efficiency programs; calculations for the business and residential
programs differ.
The Company's business progmms MW contributions are based on engineering estimates of
capacity values for installed measures; project unique factors are individually calculated for
custom projects while deemed factors are utilized for prescriptive measures. These calculations
are based on actual installed measures in the reported year. For 2012, it is calculated that 1.72
MW of capacity contribution were made available through business program energy efficiency
acquisitions. Specific hours during which business program measures contribute MW capacity
are dependent upon several factors including specific business operations and general economic
conditions.
For the residential programs, energy to capacity factor is utilized to calculate the MW savings
made available through these programs. The energy to capacity factor utilized in the calculation
(2.07 MW in 2012 for each average MWh of energy efficiency acquired) is the same as the
average load profile factor of energy efficienc,v resources selected in the 2011 IRP, i.e. the
average peak contribution of the energy efficiency resource selections across all measures and
sectors. The utilization of this factor in the MW calculation assumes that the energy efficiency
resources acquired through the Company's residential programs have the same average load
profile as those energy efficiency resources selected in the 2011 tRP. Utilization of this factor in
deternrining the MW contribution of energy efficiency programs for 2012 is detailed in the table
below.
Line Description Value
I First year EE program savings acquired during 201 2 4,095
2 Average MWh value (line 1 I 8760 hours)0.47
J Peak MW contribution of 2012 EE acquisitions 0.97
As demonstrated" it is estimated that the residential energy efficiency program acquisitions in
2012 contributed 0.97 MW of capacity contribution. As with the business programs, u,hen these
savings occur on an hourly basis is dependent upon several factors including energy usage
patterns of residential customers.
Together, the 1.72 MW's estimated for the business programs and the 0.97 MW's estimated for
residential programs make up the2.69 MW savings value of energy efficiency programs.
Rocky Mountain Power
Exhibit No. 1 Page 214 ol 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
ryHFffiHrvrouNrArN
Appendix 2
Idaho Cost Effectiveness
E,hibi T,TY Y"iTri ! :'"ffJ
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Table of Contents
Portfolio and Sector Level Cost Effectiveness ....... 3
Program Level Cost Efflectiveness...... ....................6
Home Energy Savings Program - Schedule 118............ ........................ 6
Refrigerator Recycling (See ya later, refrigerator@) - Schedule I 17............ ........... 8
Low Income Weatherization - Schedule 2l ............. .......... l0
FinAnswer Express - Schedule 1 15 ........... ...... 12
Agricultural Energy Services (Irrigation Energy Savers) - Schedule 155 ............................... 14
Energy FinAnswer - Schedule 125............ ....... 16
Page2 oflT
Rocky Mountain Power
Exhibit No. 1 Page 216 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Portfolio and Sector Level Cost Effectiveness
The overall energy efficiency portfolio and component sectors were cost effective on a
PacifiCorp Total Resource Cost Test (PTRC), Total Resource Cost Test (TRC), Utility Cost Test
(UCT), and Participant Cost Test @CT) basis.
The following table provides the results of all five cost effectiveness tests.
20 2 Portfolio and Sector Cost Effectiveness Summary PTRC TRC UCT RIM PCT
20 2 Total Enersv Efficiencv Porlfolio 1.364 1.225 1.706 0.722 2.433
20 2 C&l Energy Efficiency Portfolio 1.277 1.160 1.747 0.763 1.924
20 2 Residential Enersy Efficiency Portfolio 1.595 t.394 1.636 0.650 4.357
Sector and Program Level Cost Effectiveness Summaries:
The cost effectiveness results for the sector level are aggregations ofthe costs and benefits from
the component programs. The inputs and assumptions that support these results are contained in
the program level cost effectiveness results.
Table 1: Common Inputs
Residential Energy Rate ($/kwh)
(2012 base rate)t
Commercial Energy Rate ($/kwh)
(201 2 base rate) t
lndustrial Energy Rate ($/kwh)
(2012 base rate) t
lnigation Energy Rate ($/kwh)
2012 base rate) 1
' Future rates determined using a l.}Yo annual escalator.
Page 3 of17
Table 2: Portfolio Costs
Residential Portfolio Evaluation Costs
Table 3: Low Income Energy Education Savings
Low lncome Energy Education 20,536
Rocky Mountain Power
Exhibit No. 1 Page 217 ol 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Table 4z 2012 Total Energy Efficiency Portfolio including Low Income Education Savings
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0749 $4,760,028 $6,494,280 $1,734,253 1.364
Total Resource Cost Test (TRC) No
Adder 0.0749 $4,760,028 $s,828,886 $1,068,858 1.225
Utility Cost Test ruCf)0.0537 $3,415,751 $5,828,886 $2,413,135 1.706
Rate lmpact Test (RlM)$8,067,998 $5,828,886 ($2,239,112\0.722
Participant Cost Test (PCT)$2,962,097 $7,206,270 $4,2M,173 2.433
Lifecycle Revenue lmpacts ($/lwh)$0.000043739
Page 4 ofLT
Rocky Mountain Power
Exhibit No. 1 Page 218 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Table 6:2012 Residential Energy Efficiency Portfolio Including Evaluation Costs & Low
Table 5: 2012 C&I Energy Efficiency Portfolio including Evaluation Costs
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0786 $3,4't5,B0B $4,360,343 $944,536 1.277
Total Resource Cost Test (TRC) No
Adder 0.0786 $3,415,808 $3,963,948 $548,141 1.160
Utility Cost Test (UCf)4.0522 $2,269,257 $3,963,948 $1,694,691 1.747
Rate lmpact Test (RlM)$5,192,203 $3,963,948 ($1,228,254\0.763
Participant Cost Test (PCT)$2,342,043 $4,504,927 $2,1 62,884 1.924
Lifecycle Revenue lmpacts ($/kwh)$0.000032979
lncome Education Savings
Total Resource Cost Test (PTRC)
+ Conservation Adder 0.0665 $1,337,662 $2,1 33,937 $796,276 1.595
Total Resource Cost Test (TRC)
No Adder 0.0665 $1,337,662 $1,864,937 $527,276 1.394
Utilitv Cost Test (UCT)0.0567 $1 ,139,936 $1,864,937 $725,002 1.636
Rate lmpact Test (RlM)$2,869,237 $1,864,937 (s1.004.300)0.650
Particioant Cost Test (PCT)$620,054 $2,701,343 $2,081,289 4.357
Lifecycle Revenue lmpacts ($/kwh)$0.00001 961 8
Page 5 of L7
Roclg Mountain Power
Exhibit No. 1 Page 219 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Program Level Cost Effectiveness
Home Energy Savings Program - Schedule 118
The tables below present the cost-effectiveness findings of the Idaho Home Energy Savings
program based on Rocky Mountain Power's 2012 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 201 1 IRP 35oh load factor east residential whole house
decrement. Table I lists modeling inputs.
The program is cost-effective from the PTRC, TRC. UCT and PCT perspectives.
Table 3: Home Energy Savings Inputs
Discount Rate 7.17Y0
Residential Line Loss 11.47Y0
Residential Energy Rate ($/kWh)
(2012 base ratez)$0.1 007
Table 4: Home Energy Savings Annual Program Costs
Lighting $9,862 $1,918 $85,501 $97,281 $1 70,568
Appliance $193,291 $37,588 $167,350 $398,229 $273,987
Home lmprovement $75,044 $14,593 $52,841 $142,478 $73,829
HVAC $7,464 $1,452 $5,344 $14,260 $13,705
Total $285,661 $s5,551 $311,036 $652,248 $532,089
Table 5: Home Energy Savings Savings by Measure Type
Lighting 1,871,318 100%1 ,87'l ,318 85o/o 1,590,621 5
Appliance 522,421 100%522,421 86%449,282 15
Home lmprovement 202,826 100%202,826 87Yo 176,459 30
HVAC 20,174 100%20,174 86%17,350 1B
Total 2,616,739 2,616,739 2,233,711
t Fufure rates determined using a l.8oh annual escalator.
Page 6 of 17
Table 6: Home Energy Savings Cost-Effectiveness Results
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0569 $873,301 $1,s95,571 $722,27A 1.827
Total Resource Cost Test (TRC) No Adder 0.0s69 $873,301 $1 ,450,519 $577,21 8 t.oo I
Utility Cost Test (UCI)0.0425 $652,248 $1 ,450,519 $798,271 2.224
Rate lmpact Test (RlM)$1 ,968,615 $1,450,519 ($518,096)0.737
Participant Cost Test (PCT)$620,054 $1,847,093 $1,227,039 2.979
Lifecycle Revenue lmpacts ($/kwh)$0.00001 01 21
Discounted Participant Payback (years)1.36
Roclry Mountain Power
Exhibit No. 1 Page 220 of495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
PageT oflT
="n,onl,TYl""nTgl:'"Xr"JCase No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Refrigerator Recycling (See ya later, refrigerator@) - Schedule tL7
The tables below present the cost-effectiveness findings of the Idaho See-Ya-Later Refrigerator
program based on Rocky Mountain Poler's 2012 costs and savings estimates. The Utility
discount rate is from the 2011 Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2011 IRP 35o/oload factor east residential whole house
decrement. Table I lists modeling inputs.
The program is cost-effective from the PTRC, TRC, UCT and PCT perspectives.
Table 7: See-Ya-Later Refrigerator Inputs
Discount Rate 7.17Yo
Residential Line Loss 11.47Y0
Residential Energy Rate ($/kwh)
(2012 base rates)$0.1 007
Table 8: See-Ya-Later Refrigerator Annual Program Costs
Table 9: See-Ya-Later Refrigerator Savings by Measure Type
t Future rates determined using a7.}oh annual escalator.
Page 8 of 17
Table 1.0: See-Ya-Later Refrigerator Cost-Effectiveness Results
Etf
2.867Total Resource Cost Test (PTRC) +
Conservation Adder 0.0306 $79,551 $228,086 $148,535
Total Resource Cost Test ffRC) No Adder 0.0306 $79,s51 $207,351 $127,800 2.607
Utility Cost Test (UCI)0.0396 $102,878 $207,351 $104,473 2.016
Rate lmpact Test (RlM)$317,780 $207,351 ($110,429)0,652
Particioant Cost Test (PCT)$0 $427,909 $427,909 NA
Lifecycle Revenue lmpacts ($/kwh)$0.000004063
Discounted Participant Payback (years)NA
Rocky Mountain Power
Exhibit No. 1 Paga 222 ol 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Page 9 of 17
Roclry Mountain Power
Exhibit No. 1 Page 223 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Low Income Weatherization - Schedule 21
The tables below present the cost-effectiveness findings of the Idaho Low Income
Weatherization program based on Rocky Mountain Power's 2012 costs and savings estimates.
The Utility discount rate is from the 201I Integrated Resource Plan (lRP).
Cost-effectiveness was tested using the 201I IRP medium carbon 35o/o load factor east
residential whole house decrement. Table 1 lists modeling inputs.
With non-energy benefits added in, the program is cost-effective from only the PTRC
perspective.
Table 1: Low Income Weatherization Inputs
Discount Rate I 7.17Y0
Residential Line Loss I 11.470/0
Residential Energy Rate ($/kwh)
$0.1 007
1 2 base rater)
Table 2z Low Income Weatherization Annual Program Costs
Table 3: Low Income Weatherization Savings by Measure Type
Table 4: Low Income Weatherization Non-Energy Benefits
' Future rates determined using a 1.8%o annual escalator.
Page 10 ofL7
Table 5: Low Income Weatherization Cost-Effectiveness Results
Total Resource Cost Test (PTRC) +
Conservation Adder 0.1 387 $284,549 $301,356 $16,808 1.059
Total Resource Cost Test (TRC) No Adder 0.1 387 $284,549 $198,955 ($85,594)0.699
Utilitv Cost Test (UCT)0.1 387 $284,549 $198,9s5 ($85,594)0.699
Rate lmpact Test (RlM)$474,418 $198,955 ($275,463)0.419
Participant Cost Test (PCT)$0 $41 8,1 78 $41 8,1 78 NA
Lifecycle Revenue lmpacts ($/kwh)$0.000005763
Discounted Particioant Pavback (vears)NA
Rocky Mountain Power
Exhibit No. 1 Page 224 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Page 11 of17
Roclly Mountain Power
Exhibit No. 1 Page 225 of 495
Case No. PAC-E-IrL07
\Mtness: Kathryn C. Hymas
FinAnswer Express - Schedule 115
The tables below present the cost-effectiveness findings of the Idaho FinAnswer Express
program based on Rocky Mountain Power's 2012 costs and savings estimates. The Utility
discount rate is from the 201I lntegrated Resource Plan (IRP).
Cost-effectiveness was tested using the 201 1 IRP 690/oload factor east system decrement. Table
I lists modeling inputs.
The program is cost-efflective from the PTRC, TRC, UCT and PCT perspectives.
Table 1: FinAnswer Express Inputs
Commercial Energy Rate ($/kwh)
Table 2: FinAnswer Express Annual Program Costs
Table 3: FinAnswer Express Savings by Measure Type
s Future rates determined using a l.8oh annual escalator.
Page 12 of 17
Table 4: FinAnswer Express Cost-Effectiveness Results
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0561 $1,645,401 $2,823,990 $1,179,589 1.716
Total Resource Cost Test (TRC) No Adder 0.0561 $1,645,401 $2,567,264 $921,863 1.560
Utilitv Cost Test (UCT)0.0260 $761,001 $2,567,264 $1,806,263 3.374
Rate lmpact Test (RlM)$2,633,735 $2,567,264 ($66,472)0.975
Partrcipant Cost Test (PCT)$1,585,539 $2,784,734 $1 ,'1 99, 1 95 1.756
Lifecycle Revenue lmpacts ($/kwh)$0.000002035
Discounted Participant Payback (years)5.09
Rocky Mountain Power
Exhibit No. 1 Page 226 ol 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Page 13 of17
=,n, ontTY I"iT'i/,, ZIYI'I
Case No. PAC-E-1+07
Witness: Kalhryn C. Hymas
Agricultural Energy Services (Irrigation Energy Savers) - Schedule 155
The tables below present the cost-effectiveness findings of the ldaho Agriculture program based
on Rocky Mountain Power's 2012 costs and savings estimates. The Utility discount rate is from
the 2012lntegrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2011 IRP medium carbon 20o/o load factor
commercial cooling decrement. Table I lists modeling inputs.
The program is cost-effective from the PTRC, TRC, UCT and PCT perspectives.
Table l": Agricultural Energy Savers Inputs
Discount Rate 7.170
Aoriculture Line Loss 11.480
lnigation Energy Rate ($/kwh)
(2012 base rate)1 $0.0831
Table 2: Agricultural Energy Savers Annual Program Costs
Equipment Exchange $1 73 $3,177 $12,626 $23,099 $25,572 $64,647 $18,795
PivoUlinear Upgrade $855 $15,694 $62,368 $114,105 $108,461 $301,483 $181,1 01
System Redesigns $664 $12,191 $48,448 $88,637 $ 136,229 $286,1 69 $31 1 ,1 94
Total $1,693 $31,061 $123,442 $225,841 $270,262 $652,299 $511,090
Table 3: Agricultural Energy Savers Savings by Measure Type
Page 14 of17
Table 4: Agricultural Energy Savers Cost-Effectiveness Results
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0752 $893,1 27 $1,317,795 $424,667 1.475
Total Resource Cost Test (TRC) No Adder 0.0752 $893,1 27 $1 ,1 97,995 $304,868 1.341
Utility Cost Test (UCT)0.0549 $652,299 $1 ,1 97,995 $545,696 1.837
Rate lmpact Test (RlM)$1,575,263 $1,197,995 ($377,268)0.761
Participant Cost Test (PCT)$695,360 $1,525,995 $830,635 2.1 95
Lifecycle Revenue lmpacts ($/kwh)$0.00001 6451
Discounted Participant Payback (years)1.77
Rocky Mountain Power
Exhibit No. 'l Page 228 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
Page 15 of17
E-h i bit Xr"":Y Y"iTll! :'"I'1
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Energy FinAnswer - Schedule 125
The tables below present the cost-effectiveness findings of the Idaho Energy FinAnswer program
based on Rocky Mountain Power's 2011 costs and savings estimates. The Utility discount rate is
from the 2011 lntegrated Resource Plan (IRP).
Cost-effectiveness was tested using the 201I IRP 69Yoload fuctor east system decrement. Table
1 lists modeling inputs.
The program is cost-effective from the PTRC, TRC, UCT and PCT perspectives.
Table 1: Energy FinAnswer Inputs
Commercial Energy Rate ($/kwh)
(2012 base rate)o
lndustrial Energy Rate ($/kwh)
(2012 base rate)1
Table 2: Energy FinAnswer Annual Program Costs
Table 3: Energy FinAnswer Savings by Measure Type
u Future rates determined using a l.8oio annual escalator.
Page 16 of17
Table 4: Energy FinAnswer Cost-Effectiveness Results
Total Resource Cost Test (PTRC) +
Conservation Adder 0.0801 $180,921 $218,559 $37,638 1.248
Total Resource Cost Test (TRC) No Adder 0.0801 $180,921 $198,690 $17,769 1.098
Utility Cost Test (UCT)0.0706 $1 59,599 $198,690 $39,091 1.245
Rate lmpact Test (RlM)$286,845 $198,690 ($88,1 55)0.693
Participant Cost Test (PCf)$61,143 $1 94,1 97 $133,054 3.176
Lifecycle Revenue lmpacts ($/kwh)$0.000002367
Discounted Participant Payback (years)2.40
Roclry Mountain Power
Exhibit No. 1 Page 230 of495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
PagelT oflT
Rocky Mountaln Power
Exhibit No. 'l Page 231 of 495
CasB No. PAC-E-111-07
Wrtness: Kathryn C. Hymas
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Exhibit No. 1 Page 265 of 495
Case No. PAGE-1+O7
Wrtress: lGthryn C. Hymas
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Exhibit No. 1 Page 266 of495
Case No. PAC-E-14-07\ frtness: Kathryn C. Hymas
V.ROCKYMOUNTAIN
Kpowen
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Appendix 4
Idaho Measure Installation Verifications
Rocky Mountain Power
Exhibit No. 1 Page 267 ol 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Idaho Measure Installation Verifications
Low Income Weatherization
All projectso All measures are qualified through US Department of Energy approved audit tool or
priority list.. 100 percent inspection by agency inspector of all homes treated, reconciling work
completed and quality (corrective action includes measure verification) prior to invoicing
Company.o Community Action Partnership Association of Idaho (CAPAI) and state inspector follows
with random inspections.o Company program manager joins CAPAI and state inspectors during their monitoring
session.
Home Energy Savings
Site inspections by Program Administrator staff for the following retrofit measures (>=5 percent)
o Insulation. Windowsr Heat pump tune-upso Duct sealing and insulationo Heat pump best practices installation and proper sizing
Site inspections of 100 percent by Program Administrator staff of all heat pump water heaters.
No site inspections are conducted for the following measures. However all post-purchase
incented measures undergo a quality assurance review prior to the issuance of the
customer/dealer incentive and recording of savings (i.e. proof of purchase receipt review) and
eligible equipment review.. Additionally, customer account and customer address are checked to
ensure the Company does not double pay for the same measure or double count measure savings.o Refrigerators
r Dishwashero Ceiling fans. Light fixtureso Clothes washerso Water heaters (excluding heat pump water heaters)o Evaporative coolerso Air conditioners
Other measureso CFLs - retail channel, manufacturer agreements and program administrator sales record
reviews of qualiffing equipment. Invoicing and retail pricing is administered by program
administrator.
E,h i b*Tr"":Y Y"iTHl :'"i'"J
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
o LEDs - retail channel, manufacturer agreements and program administrator sales record
reviews of qualifuing equipment. Invoicing and retail pricing is administered by program
administrator.
Refrigerator Recycling
Company hires an independent inspector to phone survey >:5 percent program participants and
to site inspect >: l0 percent of program participants in order to verifuing program participation,
eligibility of equipment, that vendor pick-up procedures are followed (equipment is disabled at
site, kits distributed, etc.) and to survey customer experience.
FinAnswer Express
For trade alllu orosram administrated projects
Lighting projects
o Retrofits - 100 percent pre- and post-installation site inspections by third party consultant
of all projects with incentives over a specified dollar amount. Project cost documentation
reviewed for all projects.o New construction - 100 percent post-installation site inspections by third party consultant
of all projects with incentives over a specified dollar amount.o A percent of post-installation site inspections by program administrator of projects with
incentives under a specified dollar amount.
Non-lighting projects
o 100 percent of applications with an incentive that exceeds a specified dollar amount will
be inspected (via site inspection) by program administrator.o A minimum of a specified percent of remaining non-lighting applications will be
inspected. either in person or via telephone interview. by program administrator.
For Company oro-iect manaser delivered projects (lishting and non-liehting.)
Lighting and non-lightingo 100 percent pre/post-installation site inspections by third party consulting engineering
firms, invoice reconciled to inspection results.
Energy FinAnswer
All projects
o 100 percent pre and/or post-site inspections by third party engineering consultant,
inspection is reconciled with project invoice for energy efficiency retrofit measures
provided by customers. No pre-inspection for new construction.o Most projects have a commissioning requirement.
Rocky Mountain Power
Exhibit No. 1 Page 269 of 495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
All Programs
As part of the third-party program evaluations (two-year cycle) process, the Company is
implementing semi-annual customer surveys to collect evaluation-relevant data more frequently
to cure for memory loss and other detractors such as customers moving and data not be readily
available at evaluation time). This will serve as a further check veri$ing customer participation
and measures installed.
Additional record reviews and site inspections (including metering/data logging) is conducted as
part of the process and impact evaluations, a final verification of measure installations.
Rocky Mountain Power
Exhibit No. 1 Page 270 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
VROCKYMOUNTAIN
YPowER\ A DrVrSroN 0F PACIFICoBP
Appendix 5
Idaho Program Evaluations
Rocky Mountain Power
Exhibit No. I Page 271 ot 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Idaho 2012 Evaluations
Program Evaluation Recommendations and Company Responses
Evaluation reports provide detailed inforn"ration on the process and impact evaluations performed
on each program, summarizing the methodology used to calculate the evaluated savings as well
as providing recommendations for the Company to consider for improving the process or impact
of the program, as well as customer satisfaction.
Outlined below is a list of the programs, the years that were evaluated during 2012 and the third
party evaluator who completed the evaluation. Program evaluations are available for review at
rv"lr.l'.pacificorp.com/es/dsn, /idaho.htm I
Program Years Evaluated Evaluator
Home Energy Savings 2009-20 I 0 The Cadmus Group
See ya later, refrigerator 2009-201 0 The Cadmus Group
Company responses to the program recommendations contained in the 2009 - 2010 evaluations
are provided below.
The third parly evaluator's recommendations and Compan)"s responses are provided irr the
belorv Tables:
Tabie I
l-l om e Energ-r' Sa vi rrgs Eval uat i o u F{econrnrendatiurrs
Evaluation Recommendations Rockv Mountain Power Action Plan
To support Idaho lighting retailers planning to
educate customers about EISA, Rocky
Mountain Power should consider providing
educational point-of-purchase materi al s about
EISA, framed in the context of increased
availability of utility-supported, high-
efficiency lighting options. This will further
aid retailers in preparing customers for changes
in lighting availability
The Company developed an EISA
communications plan in June 2011. Materials
and messaging on EISA are already integrated
into the program's marketing plans. Messaging
doesn't focus on the specifics of EISA but
rather on educating consumers on the meaning
and difference for lumens and watts. Point-of-
purchase marketing materials for lighting
emphasize educating customers on how to
choose the right light bulb for the right
application with information on color
renderins. lumens and related information.
Train lighting retailers to properly educate and
prepare customers for EISA changes.
See above response.
Rocl{y Mountain Power
Exhibit No. 1 Page 272 of 495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
specifically the Lighting Facts label required to
be displayed on all lighting packages. Supply
retai lers with point-of-purchase materials that
will show customers how to interpret the label.
and easily find the Rocky Mountain Power-
incented bulbs they need. Although this would
not produce directly measureable savings
impacts. increased customer sati sfaction could
indirectly increase customers' willingness to
participate in other HES Program components.
Given the changes in the evolving lighting
industry, explore which higher-efficiency
lighting options (e.g., LEDs) gamer the most
savings per unit. Align rnarketing messages
with preferred lighting options to heighten
awareness usin g market transformati on tacti c s.
LEDs were added to the program in Augusl
2012.
The evolving lighting market can act as a
platform to clarifr marketing messages about
lighting options and bulbs best for each
customer's intended use. Continue to enhance
marketing collateral that compares prices of
various lighting options with expected lifetime
savings associated with those options to
demonstrate the long-ternr value of higher-
efficiency options. The potential long-term
savings attributed to qualifoing measures
served as the primary purchasing motivator for
appl i ance and weathe rization participants.
These same marketing tactics should be
considered for the lighting market, given the
elimination of traditional, inexpensive options.
Messaging should also highlight comparisons
of lighting quality and other factors consumers
tend to focus on in satisfaction surveys.
Point-of-purchase marketing materials for
lighting emphasize educating customers on
how'to choose the right light bulb for the right
application ra,ith information on color
rendering, lumens and related information.
Continue with plans to provide recyeling
centers at all participating retail locations; so
customers can simply bring in spent bulbs
when purchasing replacements. Recycling
centers could convey a positive public image to
enhance Rocky Mountain Power's reputation
within the community. and add public relations
value to the prosram. particularly with
10 lighting displays incorporating prepaid
recycling boxes were distributed to small
retailers in mid to late 2011 throughout Pacific
Power and Rocky Mountain Pow'er service
territory. It was very difficult to get retailers to
accept the displays and set them up on the sales
floor. The effort yielded no noticeable increase
in savings and didn't generate anv additional
Rocky Mountain Power
Exhibit No. 1 Page 273 of 495
Case No- PAC-E-14-07
Vvitness: Kathryn C. Hymas
Evaluation Recommendations Rocky Mountain Power Action Plan
interveners. Rocky Mountain Power should
raise awareness of the availability of recycling
centers through bill inserts. training for retail
staff. and other outreach tactics.
benefits for the retailers. The effort has been
discontinued.
Baseline wattage assumptions will need to be
updated to account for the new EISA
standards. The EISA standard established an
equivalent baseline by rated lamp lumens. If
the actual baseline wattage replaced is not
known (i.e. no surveys were conducted), the
recommended approach uses the CFL rated
lumens and equivalent lumens in EISA to
determine baseline wattage. This approach can
be use for program evaluations in2012 and
bevond.
The Company has updated baselines to
incorporate the new EISA standards and will
continue do so.
The WHF is an adjustment representing the
interactive effects of lighting measures on
heating and cooling equipment operation.
Cadmus did not apply the WHF adjustment to
lighting savings estimates as Rocky Mountain
Power did not include it in their initial
planning estimates. However, Cadmus
recommends using the approach outlined in
Apperrdix L and including this adjustment for
future plannins estimates and evaluations.
The Company has incorporated a WHF into
lighting savings.
As the baseline for lighting savings changes,
non-lighting savings garnered frorn the HES
Program may have an increased significance. lf
needed, continue to recruit new trade allies
frorn within Idal-ro to broaden progmm
awareness throughout the service territory. The
HES program has an effective trade ally
presence: an increased trade ally network could
lead to heightened incentive awareness, further
increasing program participation.
The Company constantly is recruiting new
trade allies, as well focusing on retaining
current trade allies.
To ensure trade allies find it easy to participate
and continue to promote the HES program,
carry on with plans to ofler them online
application access.
The Company has not developed online
application for trade ally projects. The
Company has developed online incentive
applications for appliances. light fixtures,
electric water heaters and room air
conditioners.
Rocky Mountain Power
Exhibit No. I Page 274 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
Continue with plans to provide trade ally-
focused marketing collateral for downloads
within the trade ally section of the program
Web pages. If possible, marketing materials
should offer personalization and/or co-
branding options for trade ally promotion.
The Company continues to use a face-to-face,
telephone, email and webinar contract
strategies for engaging trade allies for all
activities. The volume of trade ally materials
does not warrant developing a Web-based
ordering system. The Company has rolled out a
more formal communication and reiationship
strategy rryith trade allies. Webinars, a home
improvement pocket guide, frequent
communjcations and site visits, inspection
feedback, trade ally newsletters, contractor
briefs and other tools are being used to provide
more value to trade allies and to engage them
more thorouehlv and consistently.
Provide a greater quantity of'materials for trade
allies' promotional use. Develop a Web-based
tool, allowing trade allies to order these
materials as needed.
See above response.
Ensure lighting retailers are trained to inform
customers that incented lighting products have
been discounted by Rocky Mountain Power.
Lighting retailers receive visits and training
from program staffon a regular basis to ensure
they infona customers the discounted lighting
products are provided by Rocky Mountain.
Track metrics and provide results to evaluators.
Metrics help Rocky Mountain Power assess
return-on-marketing investments, and fine-tune
rnarketing resource allocations. Currently PECI
tracks online activity, program events. call-in
phone numbers and conversion information In-
house marketing evaluations can also include:
Intervieu,s; Focus groups; Sampling(i.e.,
surveys prior to and during the campaign);
Broadcast-generated impressions (i.e., assess
the total number of customers registering the
brand message through print, radio, outdoor.
sponsorship, and TV marketing);
Customer engagement/CRM Reports ;
The Company does track web analytics
closely. The Company tracks effectiveness of
events, direct mail, bill insefis and other
outbound communications. The Company will
continue to expand its use of marketing metrics
to measure effectiveness and to fine-tine
campaigns.
Continue to leverage on- and offline social
networks to leverage customer satisfaction
The Company has expanded the use of social
media (i.e. Twitter. Facebook. etc.) for
Rocky Mountain Power
Exhibit No. 1 Page 275 of495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
levels. Social networks (such as stakeholder
trade associations, community networks,
Chambers of Commerce. Linkedln groups, and
e-mail networks) provide low-cost, high-
volume information di stribution vehicles.
Continue to consider implementing innovative
tactics, such as Living Social and/or Groupon
couoon-focused lead seneration vehicles.
promoting programs. Program staff is not
engaged in local professional associations but
relies on Company staff such customer and
communi$ managers to represent the program
with local organizations.
Broaden promotion of the program's URL.
Only 6 percent of participants and l3 percent
of trade allies cited the Website as a referral
source. Online marketing can be one of the
most cost-effective tools to generate interest
and leads in remote geographies. Rocky
Mountain Power should emphasize its Website
in marketing materials as a key tool for
obtaining detailed program information.
However, marketing channels should continue
to focus on approaches reported most effective
with customers: bill inserts and in-store
displays.
Company marketing strategy has shifted from
promoting specific energy efficiency program
websites to promoting the overarching
marketing brand of wattsmart. Nearly all
program marketing materials include the
wattsmart.com address instead of the program
specific address. The Company continues to
maintain its focus on bill inserts and in-store
displays as the most effective marketing
channels with customers.
Mirror segment-driven messages fbund u,ith
collateral and promotional events on the
Website.
Marketing and messaging across channels is
consistent.
Outsource the QC process to a locally-based
QC firm. Subcontracting with a locally-based
firm with viable outside work would decrease
travel costs, and elirninate the concems of a
fulltime staff member with idle time between
installation inspections.
Quality control inspections for HVAC and
weatherization projects are done by program
staff.
To improve customer satisfaction, consider
requiring installation contractors to provide
incentive amounts as a deduction from the
customer's bill upfront, then receive
reimbursement rvhen correctly submitting the
incentive application. This would further
motivate contractors to fill out and submit
incentive forms in a timelv manner.
The Company evaluated this approach and
decided against it due to the potential for
contractors to inflate costs and the difficulty in
ensuring contractors pass along the incentive to
the customer as a deduction.
Continue to utilize marketing messages that
target the equipment replacement market.
Trade allies shouid be trained to capture this
market's interest bv oromotins the HES
The Company does encourage trade allies to
promote the program during emergency
replacement situations.
Rocky Mountain Power
Exhibit No. 1 Page 276 of495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
Program when contacted to install new
equipment in emergency replacement
situations.
Continue to leverage customer's interest tn
saving energy by providing trade allies with
materials focusing on potential energy cost
savings, associated with qualified measures.
Information could include estimated annual
and lifetinte cost savings, compared to the use
of a standard efficiency model, and using
accurate Rocky Mountain Power rates.
The Company has rolled out a more formal
communication and relationship strategy with
trade allies. Webinars. a home improvement
pocket guide, frequent communications and
site visits, inspection feedback. trade ally
newsletters, contractor briefs and other tools
are being used to provide more value to trade
allies and to engage them more thoroughly and
consistently.
Tribic l
See. r a I atel re lriEefixtor i:\'ai uati on itecontmenda ii ons
Evaluation Reeommendations Rockv Mountain Power Action Plan
Rocky Mountain Power should continue
implementing the SYLR program to achieve
cost-effective energy savings.
The Company continues to offer the program.
Rocky Mountain Power should adjust its
expected per-unit savings to reflect estimates
calculated in this evaluation. Cadmus
recommends tracking program savings using
the evaluated per-unit gross savings values of
1,190 kwh for ref'rigerators and 1.041 kWh for
freezers.
The Company adjusted kWh savings using the
RTF methodology.
Although Rocky Mountain Power did not
apply a Waste Heat Factor (WHF) adjustment
to CFL savings estimates. the WHF should be
applied to all future planning and evaluated
CFL savings values. Cadmus recommends
tracking program savings from energy-saving
kits using the WHF-adjusted gross savings
value of 63 kWh.
The Company has incorporated the Waste Heat
Factor into the 2013 reporting value for CFL
kits.
Per-unit savings can be greatly affected by
changes in appliance characteristics, such as
configuration, dg€, and size. The program
administrator tracks these characteristics, and
Rocky Mountain Power should closely monitor
chanees in oarticipatins units' characteristics.
The Company now requires an annual
summary of average participant unit
characteristics.
Roclry Mountain Power
Exhibit No. 1 Page 277 ol 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
This could be achieved by summarizing
participation data on an annual basis, and
noting changes in average participant unit
characteristics.
The progftrm administrator and Rocky
Mountain Power should continue with plans to
improve reporting processes to eliminate the
possibility of reporting discrepancies and
increase accuracy of reported results. Cadmus
identified minor discrepancies in reported
number of participant units, and Rocky
Mountain Power has since worked with the
program admini strator to prevent discrepancies
between program administrator and Rocky
Mountain Power reporting by including
additional documentation in monthlv reports.
The Company has improved monthly reporting
and invoicing to eliminate reporting errors and
improve accuracy. Monthly invoices, monthly
reports and data from the vendor are all
compared each month for accuracy against
each other.
Roclry Mountain Power
Exhibit No. 1 Page 278 of 495
Case No. PAC-E-14-07
Vltrrtness: Kathryn C. Hymas
YffiouNrArN
Appendix 6
Idaho Low Income
Weatherization lncome Guidelines I Community Action Partnership Association **d#?ifil'i|j
Vvitness: Kathryn C. Hymas
Weatlerization Income Guidelines
The Income Criteria for Idaho is set at 200% of the Federal Poverty Level - and is shown in the table below,
Family Sizr
3 Month
Income
Limtt
I ss.585
2 $7.565
3 $9.545
4 sl1.s25
5 $ l3,505
6 s15.485
7 sr?.465
I s19.445
For eadt additional person in the household beyond eight, add the following doliar amounts to the income etigibitiS
requirements: $1,980.
These income levels are effective as of July 1, 2012.
Roclq Mountain Power
Exhibit No. 1 Page 280 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
Appendix 7
Idaho Trade Allies
Rocky Mountain Power
Exhibit No. 1 Page 281 of 495
\Mtness: Kathryn C. Hymas
Energy Efficiency Alliance !,IROCKY MOUNTAIN
aPoYvER
The following is a list of contractors. distributors and other businesses participating in Rocky Mountain Power's Energy Efficiency Alliance
displayed in random order (unless sorted by the user) based on the search criteria selected. This listing is provided solely as a convenience
to our customers. Rocky Mountain Power does not warrant or guarantee the work performed by these participating vendors. You are solely
responsible for any contract with a participating vendor and the performance of any vendor you have chosen.
An asterisk (") indicates Rocky Mountain Power Outstanding Contribution Award winning trade allies in 2006, 2007, 2008. 2009, 2010,2011
andlot 2012
Search Criteria:
solected stato(s):
Specialties:
Business Typ€:
American Mechanical Sysytems
Service, LLC
7530 South State Sreet
Midvale, UT
Phone:[phone]
Website: www.ams-ut.com
Aspen Engineering andEnvironmental LLC
140 Aspen Circle
Park City, UT
Phone: [phone]
Website: www.a2e-l lc. com
Western Heating & Fireplaces
512 W Judicial
Blackfoot, lD
Phone. [phone]
GSC
668 Confluence Ave.
Murray, UT
Phone: [phone]
Website: www. gscnw.com
Bradley Engineering
382 Walnut Street
ldaho Falls, lD
Phone: [phone]
Website. www. bradleyengineering.com
Lennox"
1 008 w 2780 S
Salt Lake City, UT
Phone: [phone] x 61 14
Website: lennox.com
Electrical Wholesale Supply Co., lnc.- Rexburg
899 Jetstream Dr.
Rexburg, lD
Phone: [phone]
Website: www.ewscoinc.com
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDs
Specialties
Building envelope
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDS
Specialties
HVAC - unitary
Specialties
Food Service
HVAC - evaporative
HVAC - unitary
Specialties
Lighting
Join Date Projects1113012012 Completed
null
Join Date Proiects0311812013 Completed
ldaho
Lighting
HVAC - unitary
HVAC - evaporative
Motors and VFDS
Controls
Building envelope
Appliances
Office Equipment
Food Service
Compressed Air
Farm and Dairy
lnigation
Other
-ANY-
Search Resulfs.' 77 - Date and Time: A4/11/2013 04:19:10 PM
Business Type
Contractor
Business Type
Engineering Firm
Specialties
HVAC - unitary
Business Type
Distributor
Business TypeDistributor
Business Type
Contractor
Business Type
Manufacturer - Rep
Business Type
Engineering Firm
Join Date
09t01t2008
Join Date
12t12t2012
Join Date
09t22t2012
Join Date
11t01t2005
Join Date
09t22t2012
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
CompletedI
Specialties
Controls
Lighting
Motors and VFDs
@2012 Rocky Moudain Power, e dlvision of P.clflCorp and pad ol MldAmilcin Enlrgy Holdlng8 Comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 282 of 495
Energy Efficiency Alliance
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POYVER
ateSt
2324 amy street
fostercity, CA
Phone: [phone] x 3434
Electrical Wholesale Supply Co., lnc.
- Blackfoot
560 Jensen '. rove Rd.
Blackfoot, lD
Phone: [phone]
Website: www.ewscoinc.com
Maintenance Engineering, Ltd.
P.O. Box 2123
Fargo, ND
Phone: [phone]
Website: www. me-dtc.com
High Country H AC lnc
1306 N 1700 W
Farmington, UT
Phone: [phone]
Website: highcountryhvac.com
Allred s lncorporated
642 North 1000 West Unit ! 104
Logan, UT
Phone: [phone]
Website: www.allreds. net
Electrical Wholesale Supply Co., lnc.
- Corporate
1355 Fremont Ave
ldaho Falls, lD
Phone: [phone]
Website: www.ewscoinc.com
Total Energy Eloctrical Full
Spoctrum Services
12'1 E. 38th, 1106
Boise, lD
Phone: [phone]
Website: www.fu llspecservices.com
Wes LED Technologies, LLC.
11811 North Freeway, Suite 181
Houston, T.
Phone: [phone]
Website: www.wesled.com
Electrical Wholesale Supply Co., lnc.
- Driggs
83C Rocky Road Ind Lp.
Driggs, lD
Phone: [phone]
Website: www.ewsminc.com
ESL ision LLC
P.O. Box 58565
Salt Lake City, UT
Phone: [phone]
Website: www.eslvision.com
Dykman Electrical
2323 Federal Way
Boise, lD
Phone: [phone]
Website: dykman.com
Business Type Join Date Proiects10t05t2012 CompletedOther: Manufacturer null
Specialties
Appliances
Specialties
Controls
Lighting
Motors and VFDS
Specialties
Lighting
Specialties
HVAC - unitary
Specialties
HVAC - unitary
Specialties
Controls
Lighting
Motors and VFDS
Specialties
Lighting
Business Type
Architect
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Join Date ProjectsO4t02i2013 Completed
22
Join Date Projects09t22t2012 Completed
null
Specialties
Lighting
Specialties
Controls
Lighting
Motors and VFDS
Specialties
Controls
Lighting
Specialties
HVAC - unitary
Motors and VFDs
Business Type
Distributor
Business Type
Distributor
Business Type
Distributor
Manufacturer - Rep
Business Type
Distributor
Join Date
04to1t2009
Join Date
ost11t2011
Join Date
09t22t2012
Join Date
10t11t2012
Join Date
07 t01t2011
Join Date
09t22/2012
Join Date
o1113t2013
Join Date
08t01t2006
Projects
Completed
Projects
Completed
Proiects
Gompleted
null
Projects
Completed
null
Projects
Completed
Projects
Completed
null
Projects
Completed
Projects
Gompleted
OI12 Rocly Moudiin Pd€r, . division ot PaciflCorp .nd p.d ot MidAre.i€n Emrgy Holding! Comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 283 of495
Energy Efficiency Alliance
Wtness: Kathryn C. Hymas
V.ROCKY MOUNTAIN
xPo$rER
Clark s uality Roofing, lnc.
334 W. Anderson Avenue
Salt Lake City, UT
Phone: [phone]
Website: clarkroof.mm
Bearings & lndustrial Sales
625 Lindsay Rd
ldaho Falls, lDPhone:800-274-7775
Website: bearing-sales.com
Cralux Lighting*
759 Roberta St.
Salt Lake City, UT
Pnone.801-6734722
Website: craluxlighting.com
tah amas Controls lnc.
13526S.110W
Draper, UT
Phone: [phone]
Website: www. utahyamas.com
J1
J,I
J1, IL
Phone: [phone] x 4444
Consol idated Electrical Distributors*- Logan. T
636 N. 600 W.
Logan, UT
Phone: [phone]
Service Mechanical Controls, lnc
4410 S Century Dr
Murray, UTPhone: 801-904-1250
Thurgood Mechanical Service, lnc.
4245 E. 653 N
Rigby, lD
Phone: [phone]
Town & Country Electric, lnc.
1223 11lh Ave. North
Nampa, lD
Phone: [phone]
Website: town-and-country-electric.com
Consol idated El€ctrical Distributorsn- ldaho Falls
865 Pancheri
ldaho Falls, lD
Phone:[phone]
Coolerado Corporation
4700 W. 60th Ave., Ste. 3
Arvada, CO
Phone: [phone]
Website: coolerado.com
Cooper Lighting
1121 Highway 74 South
Peachtree, IA
Phone: [phone]
Website: www.cooperlighting. com
Specialties
Building envelope
Controls
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDs
Other: Other Specialty
Specialties
Compressed Air
Specialties
Farm and Dairy
lrrigation
Lighting
Specialties
HVAC - unitary
Motors and VFDS
Specialties
Controls
HVAC - unitary
Motors and VFDs
Specialties
Lighting
Specialties
Lighting
Specialties
HVAC - evaporative
HVAC - unitary
Specialties
Controls
Lighting
Specialties
HVAC - unitary
Motors and VFDS
Specialties
Lighting
Specialties
Building envelope
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Distributor
Engineering Firm
Manufacturer - Rep
Business Type
Contractor
Business Type
Distnbutor
Business Type
Contractor
Business Type
Contractor
Manufacturer - Rep
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Manufacturer - Rep
Business Type
Manufacturer - Rep
Join Date
09t19t2012
Join Date
10/01/2006
Join Date
05t12t2009
Join Date
01t21t2013
Join Date
01t0212013
Join Date
03126t2005
Join Date
06/01/2009
Join Date
06t01t2007
Join Date
01t01t2009
Join Date
09t24t2012
Join Date
03t01t2007
Join Date
12,1312012
Projects
Completed
null
Projects
Completed
Projects
Completed
240
Projects
Completed
Projects
Completed
Projects
Completed
27
Projects
Completed
Projects
Completed
Projects
Gompleted
Projects
Completed
7
Prolects
Gompleted
Proiects
Gompleted
O2012 Rocky Moud.in Pder. . dtuBion ol PaclffCorp .nd prn ot Miilredrn Emqy Holdlng8 Comtsny
Rocky Mountain Power
Exhibit No. 1 Page 284 of495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
D&S Electrical
363 West Chubbuck Road
Chubbuck, lD
Phone:[phone]
Tirr€ll's Electric, lnc.
770 E. Sunnyside Rd.
ldaho Falls, lD
Phone:[phone]
Munro Systems, lnc.
955 3rd Avenue/P.O. Box 519- rand Junction, CO
Phone: [phone]
erisrnic Software lnc.
65 Enterprise
Aliso Vie6, CAPhone.949-222-2287
Website: www.verismic.com
Evolve Guest Controls
85 Denton Avenue
New Hyde Park, NY
Phone:[phone]
Website. eguestcontrols.com
Electrical Wholesale Supply Co., lnc.
- ldaho Falls
3140 McNeil Dr.
ldaho Falls, lD
Phone: [phone]
Website: www-ewscoinc.com
alley lmplement
213 West 8th North
Preston, lD
Phone: [phone]
Website: valley-implement. com
Electrieal Wholesale Supply Co., lnc.
- Pocat€llo
220 West Maple
Pocatello, lD
Phone: [phone]
Website: www.ewsminc.com
All American Lighting lnc.
P.O. Box 2996
ldaho Falls, lD
Phone:[phone]
Electrical Wholesale Supply Co., lnc.
- Home Lighting
650 W. Sunnyside Rd.
ldaho Falls, lD
Phone: [phone]
Website: www.ews@inc.@m
Harris-Dudley Company
3039 S Specialty Cir
Salt Lake City, UT
Phone: [phone]
Website: radiantfl oor.com
Wheeler Electric
469 West 16th St.
ldaho Falls, lD
Phone: [phone]
Website: wheelerelectric.com
Specialties
Lighting
Motors and VFDS
Specialties
Lighting
Specialties
HVAC - unitary
Motors and VFDs
Specialties
Office Equipment
Other: Other Specialty
Specialties
Controls
Other: Other Specialty
Specialties
Controls
Lighting
Motors and VFDs
Specialties
Controls
lrrigation
Motors and VFDS
Specialties
Controls
Lighting
Motors and VFDS
Specialties
Lighting
Specialties
Controls
Lighting
Motors and VFDS
Specialties
HVAC - unitary
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Contractor
Distributor
Manufiacturer - Rep
Other
Business Type
Contractor
Manufacturer - Rep
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Join Date
12t01t2008
Join Date
03/01/2009
Join Date
09/01/2006
Join Date
01t16t2013
Join Date
06t01t2012
Join Date
09122,2012
Join Date
12t1st2012
Join Date
09t22t2012
Join Date
03101t2010
Join Date
09t22t2012
Join Date
04t01t2009
Join Date
01t01t2007
Projects
Completed
JI
Proiects
Completed
1
Projects
Completed
Projecb
Completed
Projects
Gompleted
Proiects
Completed?
Projects
Completed
null
Projects
Completed
null
Projects
Completed
1
Projects
Gompleted
null
Projects
Completed
Specialties
Lighting
Business Type
Contractor
Projects
Completed
3
@2012 R@ky Moutuin Powcr, . divilion ot P.cifiCorp end pi( ot MidAreric.n EmQy Holding! Company
Rocky Mountain Power
Exhibit No. 1 Page 285 of 495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
Control E uipment Company
174 W. Angelo Ave.
Salt Lake City, UT
Phone [phone]
Real Green LED
4280 W. 200 N.
Cedar City, UT
Phone: [phone]
Website: www. realgreen.net
Gustave A. Larson Company
1395 Northgate Mile
ldaho Falls, lD
Phone:[phone]
Website: galarson.com
Allred s lncorporated
1410 ribson Avenue
Ogden, UT
Phone: 801-621-M26
Website: www.allreds. net
orbryhn E. uipment Company
3711 E. Newby St.
Nampa, lD
Phone: [phone]
Website: norbryhn.com
L & Metco Electric
P.O. Box 7964
Boise, lD
Phone: [phone]
aman lndustrial Technologies
525 S. Utah Circleldaho Falls, lD
Phone: [phone]'l
Website: kaman.com
.,orthern Lights Electric LLC-
3473E.2O1h N. UnitA
ldaho Falls, lD
Phone: [phone]
LEPC (LeonardPetroleumE uipment )
P.O. Box 1702'19
Boise, lD
Phone: [phone]
APC Sales and Service Corp.
132 Fairgrounds Road
West tringston, RI
Phone: [phone]
Website: www. schneider-electric.com
Electric Motor Service Co.
535 Utah Circle
ldaho Falls, lD
Phone.[phone]
Website: electricmotorif.com
Thomas D. Robison Roofing, lnc.
PO Box 7'16
Blackicot, lD
Phone: [phone]
Website: robisonrooJing. com
Specialties
Building envelope
Other: Other Specialty
Specialties
HVAC - unitary
Motors and VFDs
Specialtier
Lighting
Business Type
Distributor
Business Type
Distributor
Join Date
02101t2006
Join Date
09t01t2012
Join Date
09/01/2008
Join Date
ost11t2011
Join Date
05t01t2012
Join Date
10t0112011
Join Date
09/01/2006
Join Date
04t01t2009
Join Date
09t24t2012
Join Date
03t01t2012
Join Date
05/01/2006
Join Date
06to1t2012
Projects
Completed
Proiects
Completed
Projects
Completed
Specialties
HVAC - unitary
Motors and VFDS
Specialties
Lighting
Specialties
Motors and VFDs
Specialties
Lighting
Specialties
Lighting
Motors and VFDS
Specialties
Lighting
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Contractor
Business Type
Contractor
Business Type
Other
Specialties
HVAC - unitary
Motors and VFDs
Specialties
HVAC - unitary
Business Type
Distributor
Business Type
Distributor
Proiecb
Completed
Projects
Completed
Projects
Completed
1
Projects
Completed
Projects
CompletedI
Projects
Completed
null
Proiects
Gompleted
Projects
Gompleted
Projects
Completed
Specialties
Motors and VFDS
Business Type
Distributor
Business Type
Contractor
O2012 Rcky Moufr.in Pd6r, . divirlon ot P.clfiCorp .nd p:t d Miilmric.n Ercrgy Holdingr Comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 286 of 495
Energy Efficiency Alliance
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POVI'ER
Conan s lnc.
429 W 18th St.
ldaho Falls. lD
Phone.[phone]
Larsen Electric, LLC
P.O. Box 2871
Pocatello. lD
Phone: [phone]
Honeywell lnternational
2371 S. Presidents Drive
Salt Lake City, UT
Phone: 80 I -978-7220
Website: honeywell.com
Eco Safe Lighting
4600 NW Camas Meadows Drive,
Suite 210
Camas, wA
Phone: 36O-567-1923
Website: http:/Arww. est-
lights-comlaboulus/
Midgley-Huber, lnc,*
2465 Progress Drive
Salt Lake City, UT
Phone: [phone]
Website. Migley-huber.com
First Call Jewell lnc.
'1410 Hollipark Drive
ldaho Falls, lD
Phone:[phone]
Website: fi rstcall -ewel.com
Pete s Lighting
227 S. Johnson Ave.
Pocatello, lD
Phone:[phone]Q
Thomas Electric Co
549 W 200 S
Salt Lake City, UT
Phone: [phone]
ePlusGreen lnc.
7951 SW 6th Street, Fort Lauderdale
FL 33324
Suite 208,
Ft Lauderdale, FL
Phone: [phone]
Website:
http://www.eplusgreen. com/pro/index. ht
ml
Precision-Paragon'P2:
23281 La Palma Ave
Yorlca Linda, CAPhone: 7'14-386-5550
Website: www.p.2.com
Di i Energy, LLC
68 S Main St., Ste 800
Salt Lake City, UT
Phone. 801-243-'181 1
Energy Industries
425 W Pueblo St.
Boise, lD
Phone: [phone]
Website: energy-industries. com
Specialties
HVAC - unitary
Specialties
Lighting
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDs
Specialties
Lighting
Specialties
HVAC - evaporative
HVAC - unitary
Specialties
HVAC - unitary
Motors and VFDs
Specialties
Lighting
Specialties
Motors and VFDS
Specialties
Office Equipment
Other: Other Specialty
Business Type Join Date
Manufacturer - Rep 0510112007
Business Type
Contractor
Business Type
Contractor
Business Type
Contractor
Distributor
Manufacturer - Rep
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Distributor
Engineering Firm
Other
Join Date
09/0 1 /2006
Join Date
09t2212012
Join Date
05t01t2006
Join Date
o2t11t2013
Join Date
10t01t2006
Join Date
09/01/201 0
Join Date
08/01/2009
Join Date
01t10t2013
Join Date
03t13t2013
Projects
Completed
Proiects
Completed
1
Projects
Completed
Projects
Completed
Projects
Completed
Proiects
Completed
Projects
Completed
1
Proiects
Gompleted
Prolects
Completed
Projects
Gompleted
Specialties
Lighting
Specialties
Lighting
Specialties
Lighting
Business Type
Manufacturer - Rep
Other: Manufaclurer
Business Type
Other
Business Type Join Date ProjectsDistributor 0112312013 Completed
Manufacturer - Rep
Join Date Projects05/30/2006 Gompleted
2
Om12 R6ky Mouil.in Pow6r, s dtoElon ot P.clfiCorp .hd ped of MidAme.ien Erergy Holdinf compeny
Roclq Mountain Power
Exhibit No. 1 Page 287 of 495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
ROCKY MOUNTAIN
PolVER
Royal Wholesale Electric - Logan
917 W600 N Ste 101
Logan, UT
Phone: [phone]
Website: royalutah.com
AC&H Supply
Sandy, UT
Phone: 80'1-676-7577
alley lmplement
2570 N Main
Logan, UT
Phone:[phone]
Website: valley-implement.com
Lewis Gorporation
15136 Hunfker
Pocatello, lD
Phone:[phone]
Website: lcorp.com
Platt Electric Supply-
919 Pancheri Street
ldaho Falls, lD
Phone: [phone]
Alloway Commercial Lighting
1420 i rove Street
Boise, lD
Phone:208-U4-2507
Website: www.allowaylighting.com
Electrical E uipment Company
540 W. 20th st.
ldaho Falls, lD
Phone:[phone]
Website. electricalequipment.com
D.W. Electric
4565 E. 75th N.
Rigby, lD
Phone: [phone]
Harris Aircraft, lnc.*
1405 W. 800 N.
Preston, lD
Phone: [phone]
Energy Management Corporation"
501 West 700 SouthSalt Lake City, UT
Phone: 801 -366*41 00
Website: emcsolutions.com
Skyview Electric lnc
2299 W Omni Dr
ldaho Falls, lD
Phone:[phone]
Specialties
Lighting
Specialties
Lighting
Specialties
Lighting
Other: Other Specialty
Specialties
Lighting
Specialties
HVAC - unitary
Lighting
Specialties
HVAC - unitary
Motors and VFDs
Specialties
Lighting
Motors and VFDS
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Business Type
Contractor
Business Type
Distributor
Manufacturer - Rep
Business Type
Distibutor
Business Type
Contractor
Specialties
HVAC - unitary
Lighting
Specialties
HVAC - unitary
Specialties
Controls
Farm and Dairy
lrrigation
Motors and VFDs
Specialties
HVAC - unitary
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Business Type
Contractor
Join Date
01/09/2008
Join Date
05/0't/2009
Join Date
12t05t2012
Join Dab
08/01/2008
Join Date
01t01t2009
Join Date
09t2612012
Join Date
01t01t2012
Join Date05t01nu1
Join Date
04t01t2007
Join Date
05t0112004
Join Date
02t01t2009
Projects
CompletedI
Projecb
Completed
Projects
Completed
null
Projects
Completed
Projects
Completed
b
Projects
Completed
1
Projects
Gompleted
1
Projects
Completed
I
Projects
Completed
18
Projects
Completed
Projects
Completed
@ml2 Rcky Moud.in Pder, . dili.lon ol P.clflCoQ ind p.d ot Mi4ffiic.n Ercrgy Holding! Cohp.ny
Rocky Mountain Power
Exhibit No. 1 Page 288 of495
Case No. PAC-E-14-07
VMtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
Appendix I
2012 ldaho lrrigation Post Peuk Report
Executive Sponsor
Douglas N. Bennion, P.E.
Study Team
Director
Ken Shortt
Principal Authors
Tony Perkins
Mike Anderson
Contributors
Susan Smith
Nathan Wilson
Craig Phillips
Scott Murdock
Bill Comeau
Dennis Hansen
November 2Al2
t {'t.1.1; 1, r.,:I .,.1;.r L.f,;tfjri, ttii;:,
Roclry Mountain Poiler
Exhibit No. 1 Page 289 of 495
Case No. PAGE-1+07
Witness: Kathryn C. HymasIROCKY MOTJNTAIN
FTOflERamrEx'tgHcmoanP 2012 Idaho Inigation Post Report
Inieiiirrr[,iri ir i:{l i'l;rnj..
Field Engineeing Page I of 18 I 1/2012
ZROCKY MOUNTAIN
r,lOYVER
A OrVSm OF mcrfrmnP
E,h ibitlTY Y"ITXB :,"X,"J
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
2012 ldaho lwigation Post Report
Table of Contents
EXECUTIVE STJMMARY
SYSTEM LOAD DATA ANALYSIS...............
Idaho Irrigation Load ......... ..........5
Crops Load Detail ................ ........8
Idaho Transmission System .......1 I
IRRIGATION LOAD CONTROL PROGRAM DETAILS .........12
Review of Program Results .......12
Load Control Events in2012
System Concems with Idaho Irrigation .......13
Load Control - Voltage Issues Due to Load Switching.. .. .... .....14
Idaho Switched Capacitor Project and Voltage Optimization ............ ...........15
Harmonic Issues ....................16
CONCLUSIONS
...4
Field Engineering Page 2 o.f 18 11i2012
ROCKY MOI.JNTAIN
HHIYH**
E"hibitTrTY Y""#Hl :'"ffJ
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
2012 ldaho lruigation Post Report
I rri.;:;tit,nalli' le f t *larik
Field Engineertng Page 3 of 18 I I /2012
ROCKY MOUNTAIN
FTOU/ER
E,hi bitXff Y Y"iT:l! :'"X,"J
Case No. PAC-E-I+07
Ufrtness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
EXECUTIVE SUMMARY
Rocky Mountain Power conducts an Idaho post peak irrigation system review to understand the impacts
of Idaho irrigation load, and in particular the impact of the Idaho Irrigation Load Control Program. This
annual report communicates the findings, conclusions, and recommendations resulting from the review.
First, the 2012 report analyzes system load data and irrigation load patterns during the 2012 irrigation
season (June I through September l5). It discusses total Rocky Mountain Power Idaho load versus
Idaho inigation load, and irrigation load control program participants' load versus non-participants'
load. In addition, it discusses how crop rotations and weather affect irrigation, and summarizes the
transmission system load in heavy use irrigation areas.
Second. the report analyzes the demand side management Irrigation Load Control Program and the
effects the program has on the transmission and distribution system. It discusses the details of the twelve
dispatch events for 2012 and some of the system concerns with the program.
Third, harmonic issues related to irrigation systems are discussed; however, harmonic issues are not
caused by the Irrigation Load Control Program.
Finally. the report identifies conclusions and makes recommendations.
Sonre of the key informational points from the repoft are:
o The Rocky Mountain Power Idaho irrigation typical peak demand usually occurs in late June
- early July growing season when irrigators are watering grain and potatoes at the same time.
The irrigation load in2012 followed an atypical pattem of usage. Mild winter weather and
earlier spring like temperatures allowed farmers to plant earlier. A warmer and drier spring
resulted in an earlier start to irrigatiorr.
. Irrigation load in Idaho represents 38% of the State total peak load.
o Idaho has 4,808 irrigation customers with 44o/o of these customers participating in the
Irrigation Load Control Program.
o The Irrigation Load Control Progranr was dispatched twelve times in 2012. The average
curtailment was 139 megawatts. The maximum dispatch event resulted in an estimated
curtailed load of 185 megawattsl.
. Based on work completed in 201 I and early 2012" the number of ANSI range A voltage
violations and the severity of the violations were reduced in2012.
1 See Table 1, Maximum curtailment event occurred on June 25, 2012
Field Engineering Page 4 o.f 18 I t/2012
ROCKY MOUNTAIN
PolfT'ER
',n'ont'":YY"lTl1l:'"Xr?Case No. PAC-E-14-07
\Mttness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
SYSTEM LOAD DATA ANALYSIS
Idaho Irrigation Load
Inigated agricultural land in southeastern Idaho served by Rocky Mountain Power is primarily in the
Snake River Plain. This area is an inverted triangle shape from Shelley on the south to Dubois on the
northwest and Ashton on the northeast; Arco on the west to Ririe (northeast of Idaho Falls) on the east.
Other areas in Idaho with irrigated agricultural land served by Rocky Mountain Power are: Preston,
Malad, Marsh Valley, Montpelier, and in the Gem Valley around Grace, Bancroft and Chesterfield.
These other areas have much less irrigation load than the primary area in the Snake River Plain. See
Figure I for a view of the irrigation loads. The green dots represent irrigation customers.
Irrigation water comes from either surface water-rivers, canals, ditches----or groundwater from wells.
lrrigation customers connected to the Rocky Mountain Power system use pumps driven by electric
motors to move water from the source, and pressurize it into an irrigation system. Electric pump motor
sizes reach up to 1000 horsepower.
Figure 1 Geographic Area
Field Engineering Page 5 of 18 t1/2012
v,RocKY MOUNTAINYffPiOI TER
! A, DtVtSrOt/ OF MtFrcOAP
=,n, onX,""lY l"iTlli :'"ffJ
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2012 ldalto lrrigution Post Report
Larger pump motors are used for drawing groundwater out of the deep wells in the area.
Irrigation systems can be a center pivot system' 1Figrr.2), a wheel line3 (Figure 3), or hand linesa
(Figure 4). A center pivot system will run continuously for the time it takes for a complete cycle. Wheel
lines and hand lines run 8 to 24 hours and then turned off to be moved manuallv.
Figure 3 Typical Wheel Line - Photograph
courtesv USDA NRCS
Figure 4 Typical Hand Line -
Photosraph courtesv USDA ERS
On July 2,2012 Rocky Mountain Power's ldaho loads peaked at 808 megawatts. It is estimated 690/o6 of
Schedule 72A control devices were operating on July 2, 2012. Using customer account data. there was
439 megawatts of Idaho irrigation undiversified demand in July. Applying the 690/o diversity factor
against the 439 megawatts of demand. yields 303 megawatts of total Idaho irrigation load and 505
megawatts of non-irrigation load on July 2,2012. (Figure 5)
l--_-__
i tdaho System Loading O7102120L2*
a Non irri8ation Load
Figure 5 ldaho System Loading
2 A pipe with sprinklers carried by wheeled towers in an arc around a center point.
3 A pipe with sprinklers attached on large wheels that is moved in a line across a field.a Pipes with sprinklers attached that are laid in a line on the ground.
I ldaho load was 13% of the Rocky Mountain Power total system loadt Fol. pr.por", of this report it is assumed the total irrigation population in ldaho operated at a 69% diversity factor on the peak day
Figure 2 Typical Center Pivot
Field Engineering Page 6 of 18 I 1/2012
ROCKY MOI.JNTAIN
POWER
E-hi billTY Y":THI :'"X'"J
Case No. PAC-E-'14-07
tness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
Rocky Mountain Power had 4,808 irrigation customers connected in the State of Idaho in 2012. The
undiversified demand for these 4,808 irrigation customers was 439 megawatts in July 2012. Of these
4,808 customers there are 2,117, or 44o/o, that participate in the company's Irrigation Load Control
Program (Figure 6).
ldaho lrrigation Customer s 201,2
ITotal Number of lrrigation Load Control Customers
t Total non Load Control lrrigation Customers
Figure 6 ldaho lrrigation Customers
In July, the total undiversified demand of customers participating in the load control progftlm was 261
megawatts. Applying the 69Yo diversity factor to these 261 megawatts yields 180 megawatts of
diversified load from customers participating in the load control program in July. On the day of the
peak, 180 megawatts of load was utilized by load control program participants, and 123 megawatts was
utilized by non-participating irrigation customers. This totaled 303 megawatts of irrigation load in
Idaho. See Figure 7.
ldaho lrrigation Customer Load July 2, 2Ot2
r Total bad of Load Control Customss : Total Load of Non Load Control Curtomers
Figure 7 ldaho lrrigation Customer Load luly 2,2OL2
Field Engineering Page 7 of 18 I t/201 2
ROCKY MOUNTAIN
POWER
E- hi b*lr"":Y Y,iTill :'"Xr"J
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
Idaho Crops Load Detail
The primary crops grown in the Rocky Mountain Power service territory in southeastem Idaho are
alfalfa, barley, potatoes. and wheat. Wheat, barley, and other grains are watered typically in late May,
June and July. Watering stops in late July or early August to allow the grains to dry for harvest. Potatoes
are watered through the whole summer. Alfalfa is also watered through the entire summer except during
intervals where it is cut, dried, and harvested. These dates vary each year, but generally occur in mid to
late June and late July to early August.
Figure 8 represents the periods of highest load potential using ten-year historical data from the waterino
periods of the most common crops in the program. The 2010, 201 l, and 20l2load data for the Big
Grassy substation which primarily serves irrigation load is included to denote the variability for any
given year.
eBarleYtD{%)
* Atfalf: rD {%)
rxwiEat lO(%i
* Potates lD {Y"}
***0,C Grassy sub'10 {%)
-Big
GEssy sub'r1 {?')
-8ig
Gre$y Sub'12 l%J
8-Jun 22.roa 2gtun 6-.lul 13-.lul
Figure 8 ldaho Crop Detail
Most of the variability portrayed in the graph is due to weather and the maturation period of the crops.
Alfalfa, accounting for 5lo/o of the crop within the Idaho Irrigation Load Control program, is one of the
crops that contribute to this variability since watering discontinues two to three times for harvesting.
E zo.oo6
oA$ oo.oo
zo
6 so.ooe
=5u 40.00
tsz
UE 3o.oo
1-Jun
Field Engineering Page 8 of 18 t 1/201 2
Rocky Mountain Power
Exhibit No. 1 Page 297 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. HymasROCKY MOUNTAIN
HP,,H,E#.,"2012 ldulto lrrigation Post Report
Although average crop and weather pattems provide a good indicator of what may occur, each
individual year may fluctuate drastically.
Idaho Weather
Irrigation of Southeastern Idaho crops is necessary because the rveather during the summer growing
season is typically warn and dry. The amount of spring precipitation in May and June, affects when
irrigation begins. When there is less precipitation in May and June, irrigation begins earlier.
June. July and August air temperature and precipitation affect the total summer irrigation electrical load.
Higher air temperatures and lower precipitation lead to higher summer irrigation load, since more
irrigation water will be needed on the crop. Data on precipitation, temperature. and inigation po*er'
demand for April through August of 2012 are shown in Figure 9.
April- August 2012 Weather
r 2012 Oa'ly P-ecip., inches
-2012
D:.ly HiBh Tenrp, degr€es F
-2012,8
Sub Total
Figure 9 April - August 2012: Weather and Power Use
7 See ldaho Transmission System, page 11, for a description of the eight substations referenced in Figure 9
450 -
20:
-
20,
S soo
-=*gI 3:sor.Egg<
=a 200
150
"nnso"n-1pn-1p.n*{p*pn"n-,1on-{no-,l6os.t*
Field Engineering Page 9 of 18 11/2012
ROCKY MOUNTAIN
POWER
',h,
o*t::Y y,"sTlil :r"ffJ
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
2012 ldulto lrrigation Post Report
According to Idaho Falls climate reports8, both the summer and spring were wanrrer and drier than
normal. Average temperatures were warmer in2012 by 1 degree in June, 3.5 degrees in July and 3
degrees in August.
There were fifteen days in August with the high temperature above 90 degrees and 29 days were sunny
and clear.
Average precipitation for June and July, and August is 2.22 inches. The actual precipitation total for
June. July. and August 2012was 1.07 inches,4Syo of normal. June 2012 precipitation accounted for
most of this departure from normal as precipitation that month was one inch less than normal.
A comparison between 2011 and 2012 summer weather is shou,n in Figure 10. The scarcity of June and
August precipitationin2Al2 can be seen on the graph. Also, consecutive days of temperatures higher in
2012thanin 2011 can been seen in the first and third weeks of June 2012, the second week of July, and
in late July and early August. Many of the July and early August2012 daily high temperatures were
higher than any of the summer daily high temperatures reached in 201 I .
Summer zO1,l-zOLZ Weather Compa rison
2011 DJily Prerip,,,octre;
r2012 DailV Pre.ip., tncher
-
201 i Daih HiSh Temp, de8rees F ,
-2012
Daily Hrgh Temp, degrees F
c
oA
Go
.t5t)ll
1-run 8-JJn 15-JuF 22-lun lg-Jus 13-1ul 2Gjul 27-tul 3-Aug lCLAug 17-Aug 2+Aue
I
,l ,,''r, o
Figure 10 Summer 2011 and 2012: Weather Comparison
8 Weather data is shown for ldaho Falls by the Pocatello area branch of the National Weather Service for the summer of 2012
Field Engineering Page l0 of 18
31'Aug
I 1/201 2
v,RocKY MOUNTATN
KPOl'l/ER! A DTUSION OF msFKlnP
E h'oolTY Y"i?113 :'"X'"J
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
Idaho Transmission System
Most of Rocky Mountain Power's southeastem Idaho irrigation customers are served by circuits that
originate at one of the eight major transmission substations in the area. These transmission substations
and the lower voltage distribution substations and circuits function as a system to supply power to about
9lYo of all irrigation loads in Idaho. The transmission substations, all in the Snake River Plain in
southeastem ldaho, are Amps. Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and
Rigby. In comparison to 2011 loading. the eight substation 2012 composite loading started earlier in the
surnmer and set a slightly higher peak than 2011. See Figure 1 1 .
Figure 11 ldaho Transmission Daily lrrigation Peaks
ldaho Transmission Daily lrrigation Peaks
-2011,
I Sub Total
-
2012, 8 Sub Totel
f!,1
i
!
1
l
i
-J-:
i i:iliil
!
Field Engineering PagelloflS ui20t 2
Roclq Mountain Power
Exhibit No. 1 Page 300 of 495
Case No, PAC-E-14-07
Vvitness: Kathryn C. Hymas
-,ROCKY
MOUNTAIN-(rcwep.
\ e ous,ol or ercrcone 2012 lduho Irrigation Post Report
IRRIGATION LOAD CONTROL PROGRAM DETAILS
Irrigation Load Control (SchedulesT2 & 72A) is offered to irrigation customers receiving electric
service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service. Participants allow the
curtailment of their electricity usage as prescribed in Schedules 72 and 72A in exchange for a
participation credit. For most participants their irrigation equipment is set up with a dispatchable two-
way control system giving the Company control over their loads. Participants are provided a day-ahead
notification in advance of control events and have the choice to opt-out of a limited number of dispatch
events per season. The curtailment events in this report were not in response to any limitations on
ldaho's substations or transmission systems since they have adequate capacity to serve all connected
irrigation customers in Idaho. Rather, the curtailment events are due to other factors affecting the
broader system.
Load control eYents in 2012
The 2012lrrigation Load Control Program was available for 52 hours from .lune I't to August 3l't. The
program is estimated to have curtailed 180 megawatts of load on July 2,2012, between 3 p.m. and 7
p.m. Mountain Standard Time, the peak day. See Figure 12.
'.-'....'.--"-.-'.--,
T lzlzaL2 Curtailment* i
I
i850 I
-ldaho
Load Peak I
750
<t
=r*
5s0
550 >=>6-o-<
QPAo;ii
oooo9000000000oooooooooooooodd oi c, ; 6: J r; ; + ui id r- cd ci.-l .-{ -{
Figure 12 July 2nd load curtailment profile
*Data from Hourly Data of System Loading for RMP summer 2012.
Field Engineering Page 12 of 18 11i2012
ROCKY MOUNTAINm,"
E,h i bitt"":Y Y"iTi?i :'"ffJ
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
2012 lduho lrrigution Post Report
1n2012 Rocky Mountain Power dispatched twelve irrigation load control events due to system need and
one test event on June 1 , 2012, for t hour. Idaho load control events for 2012 achieved 28o/o to 7 60/o of
the average pafiicipant connected loade.
System Concerns with Idaho Irrigation
Load Control - Voltage lssues due to Load Switching
Since change in load on the power system aflects the system voltage. an irrigation load control event
that reduces load affects system voltage. Load reduction causes the power system's voltage to increase.
sometimes above the prescribed range of ANSI C84.1. Although equipment with automatic controls is
used to adjust voltage. it does not react instantly to changes in voltage on the system, and may take up to
several minutes to adjust the voltage to the proper range in response to severe changes. To understand
and monitor voltage issues related to irrigation load control, metering was installed inside seven
different substations and on four different customer accounts on irrigation circuits. Meter readings
revealed that while the addition of the automated capacitor bank controls greatly improved the issues
observed in previous years, some voltage incursions occurred in2012. See Figure 13 for an example of
one of the voltage incursions that was observed with the metering.
s The percentages are derived from total controlled load divided by the total undiversified demand of customers participating in the load control program
of 244 megawatts for June, July, and August
Date
opt-outs
{MW}
Reductions
(MW}Dispatch Factors
6/2L/2012 6.4 156 High temp, Gen unit uncertaintv, transmission
6/22/20L2 4.9 1.62 High temp, Gen units uncertainty, transmission
6/2s/2012 10 185 High temp, Gen units uncertainty
6128/2072 L2 172 High temp, Gen units uncertainty
712/2AL2 3.4.2 180 Hieh temp, Gen units uncertainty, Prices
719120L2 13.4 L71 High temp, Gen units uncertainty, Prices
7 /L0/20L2 16.1 L57 High temp, Gen units uncertainty, Prices
7/LL/2012 16.8 L44 Hieh temp, Gen units uncertaintv
7/20/2OL2 5.9 L25 High temp, Gen units uncertainty, Prices
7126/20L2 9.6 75 Hieh temp, Gen units uncertaintv
7/2712012 10.5 77 High temp, Gen units uncertainty
818/2012 5.8 59 High temp, Gen unit uncertainty, Very high prices
Table 1, Load Control Event Dates and Data
Field Engineering Pagel3of18 r 1i201 2
Y,,ROCKY MOUNTAINKpowen! n orvrsror or mcrrrconp
', n, on X,llY I""nTill :'"X'"J
Case No- PAC-E-1+ol
Witness: Kathryn C. Hymas
2012 ldulro lwigation Post Report
Shelley Substation, Load Controlled Eventon 7h012012
iffilNjtr
-voltrlte llt
131
lri !!llt >
114
120
Figure 13, Typical load controlled event on Shelley Sub
The following factors contribute to the number of ANSI range A voltage violations:
o Large blocks of loads are controlled simultaneously. Voltage control equipment must
have ample time to react to the changes in load and adjust the voltage to keep it u,ithin
ANSI C84.1 Range A parameters. Larger magnitude changes take longer to correct.
Irrigation loads are often geographicallv concentrated in particular areas of the network.
Curtailing large blocks of participating irrigation load concentrated on a single circuit or
a single substation at the same time increases the magnitude of the voltage change.
Some circuits serve predorninately irrigation loads and have a high percentage of
Irrigation Load Control Program participants. During an irrigation load control dispatch
on these circuits the high voltage condition is magnified. The voltage exceeds the ANSI
C84.1 Rar-rge A parameters and affects other customers on the circuit.
These contributing factors are not easily resolved since there are factors. like geography. that cannot be
changed. and competing objectives involved. Demand Side Management's objective is to reduce load in
large blocks simultaneously in order to minimize system peaks and to maximize the energl,' available to
market. Operation's objective is to maintain system voltage in the proper range without incursions"
which is more difficult to do when load is reduced in large blocks. By corrtrolling smaller chunks of
load" the magnitudes of the voltage changes will be minimized. While controlling the irrigation loads in
smaller blocks rvould help decrease volta-ue incursions. it would also decrease the size of the blocks of
energy available to market, negatively impacting the prograrn's cost-effectiveness. A compromise
between the two objectives is needed.
To mitigate some of the voltage issues identified in past vears. Rocky Mountain Pou,er installed a 3-step
capacitor bank on the 69 kilovolt bus at Big Grassy substation before the 201 I irrigation season. The
stepped capacitor bank is working well. See Figure 14.
Field Engineering Page 14 o.f 18
ROCKY MOUNTAIN
PIOWER
.- n, o oX,XlY I""nT:* :'"1'1
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2012 ldslto lrrigation Post Report
Idaho Switched Capacitor Project and Voltage Optimization
In 2011, as part of Rocky Mountain Power's efforts to minimize voltage incursions and not put a cap on
load control enrollment, Rocky Mountain Power agreed to install automatically switched capacitor bank
controls. To address the system and cost-effectiveness issues. a settlement was reached in 2011 with the
Idaho Commission staff, the Idaho Irrigation Pumper Association, and Rocky Mountain Power. The
settlement stated that Rocky Mountain Power would invest a minimum of $1.3 million dollars before the
2012 irfigation season to reduce the constraints on the system during high participation in the Inigation
Load Control Program.
To comply with the settlement agreement Rocky Mountain Power engineered a solution to the problem
by replacing manual capacitor banks with automatic sensing capacitors that would srvitch automatically
to maintain acceptable voltage levels. Forty Six automatic switched capacitors have been installed and
59 manual capacitors were removed. This work was completed on l4 circuits before the start of the 2012
irrigation season.
Voltage meters were installed on the 7 substations supplying the 14 circuits. Four additional meters were
placed on the distribution circuits to monitor voltages to insure. These meters allow for optimization of
the new capacitor controls and ensure they are working properly. Figure l4 illustrates the voltage srvings
on the 69 kilovolt bus which were less than previous years.
Big Grassy Voltage
201 0
1-May 8-May 15-May 22"May 29'May s"lun 12"Jun 19"lun 26'Jun 3-.lul to-lul 17'Jul 24Jul 31'lul 7-Aug l4-Aug 21-Aug 2S-Aug i
Figure 14, Big Grassy Voltage
I
i
I
Field Engineering Pagel5of18 11/20t2
ROCKY MOUNTAIN
POWER
.- n, on T,"":Y y"lT:li :,"Ir";
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
2012 ldalto lrrigation Post Report
Harmonic Issues
Rocky Mountain Power saw fewer harmonic issues in 201 2, after a substantial increase in harmonic
issues during the 2011 irrigation season. It is important to mention that harmonic pollution is unrelated
to the ldaho's Irrigation Load Control Program. The largest contributors to the hannonic pollutiorr on
Rocky Mountain Power's irrigation feeders are unfiltered variable frequency drives used on large
irrigation pumps. The company's mitigation effort to significantly reduce harmonic pollution appears to
be working: however, harmonic issues in the area continue to be of a concern to Rocky Mountain
Power. In comparison to 201 1" 2012 saw feu,er incidences of center pivot swing arms steering away
from the desired path of travel. On one circuit. several variable fiequencl'drive pump loads that u,ere
violating harmonic limit levels added filtering equipment to their electrical panels. This has resulted in a
sharp drop in complaints related to the malfunctioning of guidance system of the center pivot swing
arms.
Hannonic pollution caused by unfiltered variable frequency drive pump loads leads to the irrigation
center pivot swing anns steering a\vay from their pre-determined paths of travel. An electrically charged
trace wire is buried in the ground that provides the sensors in the center-pivot swing arnls a path to
follow. The signal on the trace wires is similar to the I 3th. l Ttl'. and 19th harmonics currents produced b-v
unfiltered variable fi'equency pump motor drives. The antennaarray used by,the pivot system can be
influenced by the elevated harnonic levels. This can cause the srving arm to steer aw,ay from the desired
path. Figure I 5 shows a typical antenna amay system that is used to follorv the buried trace u,ires.
Only four pivots left their intended path in 2012. Tlvee pivots left their intended path in 2009. one pivot
left its intended path in 2010 and eight pivots ieft their intended paths in 201 l. Five of the troubled
pivots in 201 I left their intended path multiple times.
Figure 15, Typical Center Pivot Antenna Array
Efforts to mitigate the issues from harmonic pollution included several strategies. First. Rockl'Mountain
Por.ver provided better feedback and education to irrigators and electrical contractors regarding the
importance and application of filtering for variable frequency drives to insure I EEE 5 1 9 compliance. [n
prior years some of Rocky Mountain Power's custonlers had been unwilling to add harmonic filtering to
Field Engineering Page 16 of l8 I ti:012
ROCKY MOUNTAIN
HggE*-,
E-hibi t::Y Y""sTgl :'"X'1
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
their variable frequency drives. This is now corrected and cooperation with irrigators was good during
2012.
Second, Rocky Mountain Power reviewed susceptibility issues with center-pivot system designers and
manufacturers. According to the center-pivot manufacturers, the designs have successfully worked for
the last 30 years with very few problems and they were thus unwilling to change their swing arm
tracking design. Further, the incompatibility of harmonic guidance systems and harmonics from variable
frequency drives has not been well understood since variable frequency drives were not widely used in
irrigation systems until recent years. In the future GPS tracking swing arrns are expected to replace
current technology which will help alleviate the existing guidance problem.
Last. Rocky Mountain Power must continually monitor the status of distribution line capacitor banks.
Capacitors act as higher frequency sinks for higher order harmonics. Thus, if a capacitor bank is not
working correctly, there is a high chance that the harmonic pollution levels on the system could affect
tracking of the center-pivot swing arm.
Rocky Mountain Power will continue to monitor harmonic issues and address customer complaints in a
prompt and efficient manner. The company expects its mitigation eflorts along with effective customer
participation to reduce hannonic pollution. This is needed to provide reliable electric service and
improved customer satisfaction.
CONCLUSIONS
The report analysis leads to these conclusions:
. Idaho's overall peak load was 808 megawatts on July 2,2012 and the irrigation peak at the same
time was 303 megawatts.
o The ldaho irri-eation load represents a significant percentage of ldaho's peak load, 38olo.
o The Irrigation Load Control Program was dispatched twelve times in 2012. The average
estimated curtailment was 139 MW
o The distribution system improvements that were added prior to the 2012 irrigation season
minimized the voltage swings on the 69 kilovolt bus at Big Grassy substation.
o Voltage incursions occurred during load control events due to the Idaho Load Control Program.
However, the capacitor bank automated control installation project minimized the number and
frequency of voltage incursions. The number of meters available to collect voltage data was
insufficient to analyze all circuits in the system.
o Harmonic pollution on Rocky Mountain Power's irrigation distribution circuits, was less
fiequently a problem in2012, but continues to be an issue and has caused ir:rigation pivots to
walk offtheir intended paths and, in some instances, contact distribution lines.
Field Engineering Page l7 of l8 t 1/2012
ROCKY MOUNTAINFolilER
.-n, onT,TY I"iTSl :'"X'"J
Case No. PAC-E-1+07
\ frtness: Kathryn C. Hymas
2012 ldaho lrrigation Post Report
RECOMMENDATIONS
o Future distribution circuit and voltage monitoring will need to continue to make sure the system
is operating properly.
o Meter Engineering needs to develop an effective voltage monitoring set up including, site
specifications, meter type and appropriate options, and automated data retrieval system, and
establish a dedicated team familiar with project goals and expected outcomes.
o The company needs to continue its efforts to education irrigators about variable frequency drives,
harmonic pollution mitigation and customer's responsibility for their own systems.
Field Engineering Page 18 of I8 I 1/2012
Rocky Mountain Power
Exhibit No. 1 Page 307 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
ROCKY MOUNTAIN
IPOWER
A OIV'SION OF PACIFICORP
Exhibit No. 1.4
2013 Annual Report
Rocky Mountain Power
Exhibit No. 1 Page 308 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Idaho Energy Efficiency and
Peak Reduction Annual
Report
January 1,2013 - December 31 ,2073
Issued May 1,2074
ROCKY MOUNTAINPOWER
Let's turn the onswers on.
Rodry Mountain Power
Exhibit No. 1 Page 309 of 495
Case No. PAC-E-1+07
\r1/ntness: Kathryn C. Hymas
(This page intentionally left blank)
Page2 of 43
Rocky Mountain Power
Rocky Mountain Power
Exhibit No. 1 Page 310 of 495
Case No. PAC-E-1+07
YIEiESFeb?ltufltrIdaho Report
T;\BLE OT CONTENTS
List of Abbreviations and Acronyms............. ......... 5
Executive Summary ............6
2013 Perfornance ...........9
Regulatory History...... ...... l0
Schedule 191, Customer Efficiency Services Rate Balancing Account Summary................... l l
Planning Process ...............12
Integrated Resource P1an........... ......12
Irrigation Load Contro1.............. ..... 15
Program Management............... ..................... 15
Program Administration............ .................... 16
Load Control Events and Performance........... ................. 16
Evaluation .................. 16
Energy Efficiency Programs ...............17
Residential Programs ........17
Home Energy Saver Program.... ......17
Program Management............... ..................... 18
Program Administration............ .................... 19
Infrastructure .............. ................. 19
Demographics............. .................23
Evaluation ..................24
Refrigerator Recycling ....................24
Program Management............... ............-........25
Program Administration............ ....................25
Infrastructure .............26
Evaluation ..................26
Low Income Weatherization ...........26
Program Management............... ..........-..........27
Program Administration ............ ....................28
Evaluation ..................28
Low Income Energy Conservation Education ....................28
Commercial and Industrial Programs................ .....................31
FinAnswer Express .......31
Page 3 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 31 1 of 495
Case No. PAC-E-1+07
YIBIE8f,Ubhtgfltr
Page 4 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 312 of 495
Case No. PAC-E-1+07
Abbrevi atioH$ffi dfl UtSrfyfl ffi
CFLs
CAPAI
DSM
EICAP
HVAC
IECC
IDHW
IRP
kwh
LEDs
LIHEAP
MW
NTG
PCT
PTRC
RIM
Schedule
SEICAA
TRC
UCT
191
Lrsr or ABBREVTATToNS AND AcRoNyMS
Compact Fluorescent Lights
Community Action Partnership Association of Idaho
Demand-Side Management
Eastern Idaho Community Action Plan
Heating, ventilation and air conditioning
Intemational Energy Conservation Code
Idaho Department of Health and Welfare
Integrated Resource Plan
Kilowatt hour
Light-emitting Diode Lights
Low Income Home Energy Assistance
Megawatt
Net-to-Gross
Participant Cost Test
Total Resource Cost Test with 10 percent adder
Ratepayer Impact Measure Test
Customer Efficiency Services Rate
SouthEastern Idaho Community Action Agency
Total Resource Cost Test
Utility Cost Test
Page 5 of43
Rocky Mountain Power Idaho Report
Roclq Mountain Power
Exhibit No. 1 Page 313 of495
Case No. PAC-E-1+07
Exuulittr/8surfiffi
Exrcutn r Surrnrany
Rocky Mountain Power ("Company") working in partnership with its retail customers and with
the approval of the Idaho Public Utilities Commission ("Commission") acquires energy
efficiency and peak reduction resources as cost-effective altematives to the acquisition of supply-
side resources. These resources assist the Company in efficiently addressing load growth and
contribute to the Company's ability to meet system peak requirements. Company energy
efficiency and peak reduction programs provide participating Idaho customers with tools that
enable them to reduce or assist in the management of their energy usage while reducing the
overall costs to the Company's customers. These resources are relied upon in resource planning
as a least cost altemative to supply-side resources.
This report provides details on program results, activities, expenditures, and Customer Efficiency
Service Charge - Schedule l9l ("Schedule 191") - revenue for the performance period from
January 1,2013, through December 31,2013. The Company, on behalf of its customers, invested
$3.9 million in energy efficiency resource acquisitions during the reporting period. The
investment yielded approximately 20.2 gigawatt-hours in first year savingsl and approximately
3.4 megawatts of capacity reduction from energy efficiency2. Net benefits based on the projected
value of the energy efficiency program savings over the life of the individual measures are
estimated at$2.4 million3. The cost effectiveness of the energy efficiency portfolio from various
perspectives is provided in Table 1.
The company also offers an irrigation load management program to agricultural customers in the
state of Idaho. The program is positioned as a system resource and as such its costs are not
recovered through Schedule 191. Additional information on the irrigation load management
program is provided later in this report.
rReported savings at generation.
2 See Appendix I for explanation on how the capacity contribution savings values are calculated.
3 See Table I - Utility Cost Test Net Benefits.
Page 6 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. I Page 314 of 495
Case No. PAC-E-1+07
Exuulitir,l8tstfififfi
bl I *-Cost E{}bciivencss lbr the E E{lt Portfblifi.t:)Ie i *-s I()r lile ,rt]L)i t()
Benefit/Cost
Ratio
Net Benefits
Total Resource Cost Test plus 10 percent (*PTRC") - total resource cost with 1.26the addition of environmental and benefitsa $r.754.222
Total Resource Cost Test ("TRC")'l.l5 $1,002.449
Utiliw Cosr Test ("U l.5l $2.436,051
Participant Cost Test 1.95 $6.128.360
Ratepayer Impact ("RIM")"0.63 ($4,66t,724)
The energy efiiciency portfolio was cost effective based on four of five standard cost
effectiveness tests for the reporting period. The ratepayer impact measure test was less than 1.0
indicating near-terrn upward pressure was placed on the price per kilowatt-hour given a
reduction in sales. Annual performance information for 2013 cost effectiveness is provided in
detail in Appendix 2.
In 2013, the Company completed development of the Technical Reference Library which
contains preliminary measure-level savings data, including the methods, assumptions and
sources for those assumptions used for reporting of energy savings. The Energy Efficiency
Measures report is provided in Appendix 3.
Another Company system implementation that began in 2013 was the upgrade of the tracking
system which is used by Demand-Side Management ("DSM") to store information on completed
customer projects. The system is known as DSM Central and integrates with the Technical
Reference Library.
The Company, working with its third-party delivery administratorse collaborates with the
following number of retailers, contractors, and vendors in the delivery of its energy efficiency
programs in the state of Idaho:
' The TRC plus 10 percent includes a benefit adder to account for non-quantified environmental and non-energy
benefits of conservation resources over supply-side alternatives.5 The TRC compares the total cost of a supply-side resource to the total cost of energy efEciency resources,
including costs paid by the customer in excess of the program incentives. The test is used to determine if an energy
efficiency program is cost effective from a total cost perspective.u The UCT compares the total cost incurred by the utility to the benefits associated with displacing or deferring
supply-side resources.
' The PCT compares the portion of the resource paid directly by participants to the savings realized by the
participants.t The RIM examines the impact of energy efliciency on utility rates. Unlike supply-side investments, energy
efficiency programs reduce energy sales. Reduced energy sales lowers revenues (see UCT) putting upward pressure
on rates as the remaining fixed costs are spread over fewer kilowatt-hours.
' See program specific J"ction, for backgrounds on third-party administrators.
Page 7 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Po^rer
Exhibit No. 1 Page 31 5 of 495
Case No. PAC-E-1+07
ExUUuthl8tstfttuil6ff
Table 2 - Energy Efliciency Inflastructure
Sector Tvpe No.
Residential Lishtins Retailers 22
Appliances Retailers z3
HVAC'" Contractors 14
Insulation Contractors t7
Low Income Aeencies 2
Commercial and lndustrial Lishtins Trade Allies 52
HVAC Trade Allies 29
Motors & VFD Trade Allies 28
Eneineerins Firms .tn
10 Heating, ventilation and air conditioning
Page 8 of43
Rocky Mountain Power ldaho Report
Rocky Mountain Power
Exhibit No. 'l Page 316 of 495
Case No. PAC-E-14-07
ExWEttiSSUlfiffi
2{}13 Perftirrt,&tce
Program and Sector level results for 20 I 3 are provided in Table 3.
Tabic l
Idaha Pro{r*rtt Results 1'or.lanuat'r' l. lfll i * l}ccenrber
See Appendix 4 for breakdown ofprogram expenditures by category.
rrThe values at generation include line losses between the customer site and the generation source. The Company's
line losses by sector for 2013 are 17.47 percent for residential, 10.75 percent for commercial,7.52 percent for
industrial and 1 1.45 percent for irrigation.
Program
kWh/Yr
Savings
(at site)
kWh/Yr
Savings
(at generator)
Program
Expenditures
Low Income Weatherization (21)101,771 tt3.44C s 203-741
Refrigerator Recycling (I I7)692.799 772235 $92.3s3
Home Enerw Savinss (l l8)2.512,46'1 2.800,s47 $ 825,450
Total Residential 3.307.037 3.686.222 $ 1.121.544
Enerpry FinAnswer (125)42s205 470910 $ 74,625
FinAnswer Exoress (1 15)2207.s04 2.444.789 s 597-379
Total Commercial 2.632.709 2.915.699 $ 672.004
Energr FinAnswer (125)1914,074 2,058,051 s 2s4.249
FinAnswer Exnress (l 15)2,97938s 3.203,494 s 362.s73
Total Industrial 4.893.459 5.26t.545 s 616.822
FinAnswer Express (1 15)169,154 188.519 $ 17,567
Asricuhuml Enerw Services (155)7,321,543 8,159,713 s r,180,575
Total Asricultural 7.490.697 8.348.232 $ 1.198.143
Total Enersv Effciencv 18,323.902 20.211.698 3.608.512
Commercial & Industrial Evaluation Costs
Residential Evaluation Costs
Low Income Enerry Conservation Education
Technical Reference Library
DSM Central
Total System Benefit Expenditures - All Programs
$
$
$
$
$
73,655
129.658
25,000
23,705
13.566
3,974,096
Page9 of 43
Rocky Mountain Power
Exhibit No. 1 Page 317 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report RggmatSfyrftdtwT
RrcullroRY HrsroRY
During the reporting period the Company filed a number of compliance and/or informational
reports, updates and requests with the Commission in support of the Company programs. The
following is a Iist of those filings:
o On March 8, 2013, the Commission approved the Company's application filed on
December 7,2012, to cancel Irrigation Tariffs 72 and 72A and approve the new Irrigation
Load Control Contract.
On April 25,2013, pursuant to Order No. 29976, the Company submitted its 2012Idaho
Energy Effrciency and Peak Reduction Annual Report.
On May 15, 2013, pursuant to Order No. 32788, the Company filed a revision to
Schedule 21 - Low Income Weatherization Services Optional for Income Qualifying
Customers, sheet no. 3, to include $25,000 for the low income conservation education
fund. The Commission approved the updated tariff sheet with an effective date of June l,
2013.
On May 24,2013, in Case No. PAC-E-13-10, the Company filed to revise Schedule 155
- Agricultural Energy Services to suspend: (l) the Nozzle Exchange Program; and (2)
incentives for the pivot and linear equipment measures listed in the tariff. The
Commission approved the request in Order No. 32879, effective August 15,2013.
On November 7,2013, in Case No. PAC-E-13-15, the Company filed for approval of a
one-time customer credit to refund over collection of Schedule 191 Customer Efficiency
Services rate ("Schedule 191"). The refund was approved by the Commission in Order
No. 32967 on January 23,2014.
Page 10 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 318 of495
Case No. PAC-E-14-07
Rgg\ilil8l'JvtftdtwT
Sr:hedule l9l" Custat*er Effic:ir:nt3'St:rvicr^1,'ffcrls *lal*ndng,4r,co*rtt Suntmur.t'
In Case Number PAC-E-OS-10 (Order No. 29976) the.Commission approved the recovery of all
DSM program costs through Schedule 191, with exception of the expenses associated with the
irrigationload control program12. Schedule 191 charges appear as a line item on customer bills.
The Company books eligible DSM program costs as incurred to the balancing account.
Schedule l9l balancing account activity for 2013 is outlined in Table 4.
'r ^:-i Ii -1 !i: -l
\uir.'..-llrll 'tr t lill:t.;t;ir::- . iuL'ouni \i'ii', i't ,
Monthly
Program Cost -
Fixed Assets
IBalance as of 12131112
lJanuary $ 187.387
$ 386.782
$ 278.520
$ 327.009
$ 159.914
$ 148.490
s 350.917
s 232.359
s 246.269
s 353.699
$ 345.194
$ 799.125
Carrying
Rate Recovery Charye
japrit
itutuy
i Junei
iJul,vIiAugust
is.pt rb.t
lNovember
Monthly Net
Accrued
Costs *
Cash Basis
Accumulated
Balance
$ (690.167)
" $ (770,378)
$ (637.366)
s (585,910)
$ (4s6,170)
$ (584.268)
$ (900.4e9)
$ (1.r84.678)
$ ( r.475.929)
$ ( r.634.799)
Accrual Basis
Accumulated
Balance
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
s
$
$
$
$
$
$
$
$
$
$
s
$
$
$
s
$
$
$
$
$
91.691
(32.874)
35.772
(s5.624)
(e0.761)
(21.930)
(2.503)
22.731
(8.033)
14.287
23.813
(266,990) $
(2s3.r84) $
(226"555) S
(re6.836) $
(287.578) $
(464.103) $
(634228) S
(522.s02) $
(403.843) $
(286.305) $
(235.147) S
(608)
(586)
(50e)
(434)
(433)
(618)
(868)
( r.1 08)
(1296\
( r.s68.740)
( 1.459.953)
(370.753
(359.273
(654.8 I
(941.493
(r2r0,0r3
(12e6.
( r.r63
625,565(1 247.067) S
i 2013 totals $ 3,815.666 $ (4,024,339) $(10,042)
* December 2013 total accrual 283.317
Column Explanations:
Monthlv Proeram Costs - Fixed Assets: Monthly expenditures for all energy efficiency program activities.
Monthly Net Accrued Costs: Monthly net change of program costs incurred during the period not yet
posted.
Rate Recovery: Revenue collected through Schedule 191.
Carrvine Charge: Monthly "interest" charge based on "Accumulated Balance" of the account. The current
"interest rate" for the Accumulated Balance is I percent per year.
Cash Basis Accumulated Balance: Current balance of the account - a running total of account activities. A
negative accumulative balance means cumulative revenue exceeds cumulative expenditures; positive
accumulative balance means cumulative expenditures exceed cumulative revenue.
Accrual Basis Accumulative Balance: Current balance ofaccount including accrued costs.
'' The Commission, in Case No. PAC-E-10-07, ordered that the costs associated with the Idaho Irrigation Load
Control Program should be allocated as system costs and not situs to Idaho.
Page 11 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 319 of 495
Case No. PAC-E-1+07
fmirrtf?t'UlPfotves
Plal.ixrxc Pnocrss
kttegrated Reso u rc:e Ptan
The Company develops a biennial integrated resource plan ("lRP") as a means of balancing cost,
risk, uncertainty, supply reliability/deliverability and long-run public policy goals. The plan
presents a framework of future actions to ensure the Company continues to provide safe, reliable,
reasonable-cost service with manageable risks to its customers. Energy efficiency and peak
management opportunities are incorporated into the plan based on their availability,
characteristics and costs.
Energy efficiency and peak management resources can be divided into four general classes based
on their relative characteristics, the classes are:
Class 1 DSM (Resources from fully dispatchable or scheduled firm capacity product
offerings/programs) - Capacity savings occur as a result of active Company control or
advanced scheduling. Once customers agree to participate, the timing and persistence of
the load reduction is involuntary on their part within the agreed limits and parameters.
Class 2 DSM (Resources from non-dispatchable, firm energy and capacity product
offerings/programs) - Sustainable energy and related capacity savings are achieved
through facilitation of technological advancements in equipment, appliances, lighting and
structures or sustainable verifiable changes in operating and maintenance practices, also
commonly referred to as energy efficiency resources.
Class 3 DSM (Resources from price responsive energy and capacity product
offerings/programs) - Short-duration energy and capacity savings from actions taken by
customers voluntarily based on pricing incentives or signal.
Class 4 DSM (Resources from energy efficiency education and non-incentive based
voluntary curtailment programs/communications pleas) Energy and/or capacity
reduction typically achieved from voluntary actions taken by customers, to reduce costs
or benefit the environment through education, communication and/or public pleas.
As technical support for the IRP, a third-party analysis is conducted to estimate the magnitude,
timing and cost of alternative energy efficiency and peak management options.13 The main focus
of the study is on resources with sufficient reliability characteristics anticipated to be technically
feasible and assumed achievable during the IRP's 2}-year planning horizon. The estimated
achievable energy efficiency potential identified in the 2013 study for Idaho was 34 average
megawatts or 13 percent of retail sales.la By definition this is the energy effrciency potential that
may be achievable to acquire during the 20-year planning horizon if determined least cost and
cost-effective compared to supply-side alternatives within the Company's integrated resource
planning process.
" Assessment of Long-term, System-Wide Potential for Demand-Side and Other Supplemental Resources,
www.pacificorp.com/contenVdamipacificorp/doc/Energy_SourceslDemand_Side_Management/DSM_Potential_Stu
dylPaci fi Corp_DSMPotential_FINAL_V olYo20l.pdf .talbid, page 75.
Page 12 of 43
Rocky Mountain Power Idaho Report
Roclry Mountain Power
Exhibit No. 1 Page 320 of 495
Case No. PAC-E-14-07
Pffiif?lg??dil€tr
The achievable technical potential for Idaho by sector is shown in Table 5. The 2013 potential
study indicates that 5 percent of the achievable technical potential for the Company, excluding
oregonls, is in Idaho.16
'I'able 5
Etfi cienc,r, Acirie'n,atrl e'f echlT i cal Pcllenti a I hv Sector[.-,rterir\.
i Average Megawatts in
]| 2032 l Percent of Retail Sales I
l6 l5o/o i
-,--"--',]15o/o
Industrial 8%
l0o/o
* Note there is an additional 0.2 aMW associated with street lights
Energy efficiency resources vary in their reliability, load reduction and persistence over time.
Based on the significant number of measures identified in the potential study it is difficult to
incorporate each measure as a stand-a-lone resource in the IRP. To address this issue, energy
efficiency measures are bundled by their relative cost to reduce the number of combinations to a
more manageable number.
The evaluation of energy efficiency resources within the IRP is also informed by state specific
evaluation criteria. While all states generally use commonly accepted cost effectiveness tests,
some states require variations in calculating or prioritizing the tests.
o Washington and Oregon utilize the total resource cost but allow for consideration of non-
energy benefits and a 10 percent regional conservation credit in the determination of cost
efflectiveness.o Utah utilizes the utility cost test as the primary determination of cost efflectiveness.
The Company evaluates program implementation cost effectiveness (both prospectively and
retrospectively) under a variation of five tests to identifu the relative impact and./or value to
customers and the Company (i.e. utility cost, total resource cost, near-term rate impact, program
value to participants. etc.).
The 2013 Integrated Resource Plan preferred portfolio includes the acquisition of energy
efficiency resources. The plan seeks opportunities to accelerate these acquisitions as evidenced
by the range of the savings target and expanded set of demand side management related Action
Plan activities. The action plan savings targets for the 2013 Integrated Resource Plan t' are
shown in Table 6.
r5 Demand-side Management potential studies are performed by the Energy Trust of Oregon.
'o Page 75,Table 52 of the 2013 Assessment of Long-term, System-Wide Potential for Demand-Side and Other
Supplemental Resources.t' 2013 IRP, April, 2013,
lr,*'w.pacificorn.conr,/content/darn,'pacificorp/doc;'Enerq)' Sourcesi Integrated Resource_PIan120 I 3lRP,?acifiCoro-
201 3lRP Vol l -Main 4--30- l3.ndL page 248.
I
Page 13 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 321 of495
Case No. PAC-E-1+07
ryrffi#llgP?oUds
Table 5
P re{brred I'}o*fb li o Energy ii fliciency'['argets
2013 Preferred Portfolio I Acquire 1,425-1,876 gigawatt hours (GWh) of cost-effective Class 2
(energy efficiency) resources by the end of 2015 and2,034-3,180 GWh by
the end of2017.
Page 14 of43
Rocky Mountain Power
Exhibit No. 1 Page 322 ol 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report
FE,tx Rsou crrt)N PR0c;It",1!1s
Peak Reduction programs assist the Company in balancing the timing of customer energy
requirements during heavy use summer hours; deferring the need for higher cost investments in
delivery infrastructure and generation resources that would otherwise be needed to serve those
loads for a select few hours each year. These programs help the Company maximize the
efficiency of the Company's existing electrical system and reduce costs for all customers.
lrrigati o * L*utl {-ovr tro{
The Irrigation Load Control program was offered to irrigation customers receiving electric
service on Schedule 10, Irrigation and Soil Drainage Pumping Power Service. Participants
enrolled with a third party to allow the curtailment of their electricity usage in exchange for a
participation credit. For most participants, their irrigation equipment is set up with a
dispatchable two-way control system giving the Company control over their loads. Under this
control option. participants are provided a day-ahead notification in advance of control events
and have the choice to opt-out of a limited number of dispatch events per season.
A summary of the program performance, participation and cost effectiveness results for the
program period of June 10,2013 - August 16,2013 are provided in Tables 7 and 8.
Tabie 7
Irri3alicrrr l.oarj ( oniroi Pr:grar:: P*rlbrmaucr-
Pe ak RUdlfSti 61T Tri'E #dlti
:rotit er*il"d Mwicfi;:iicenl 1 vg -:
, Average Realized load (at Gen) I 150 ,
, Maximum Realized load (at Gen) i 186 i
Participation Customers L ^a^ i
l
, !".t,rry1'_"_, LqiP__ i 271 i
I :rbic S
{ erst i:.i'icrtir *;r;ss li:r }rriqaiii:n i.oaii [.riittilrl
Benefit/Cost
Ratio
i utility cost Test Pass
_!eluee49g{}$_ I N/A :
Rate Payer lmpact Pass
Program Management
The program manager who is responsible for the
also responsible for the lrrigation Load Control
Irrigation Load Controi program in Idaho is
program in Utah. For each state the program
Total Resource Cost Test
Total Resource Cost Test
Page 15 of43
Rocky Mountain Power
Exhibit No. 1 Page 323 of495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report
manager is responsible for the cost effectiveness of the program, contracting with program
administrator through a competitive bid process, establishing and monitoring program
performance and compliance, and recommending changes in the terms and conditions set out in
the tariff.
Prosram Administration
Starting with the 2013 program season, the Company selected EnerNoc to manage the irrigation
load control program through a pay-for-performance structure. See Appendix 5 for EnerNoc's
2013 PacifiCorp Irrigation Load Control Program Report.
Load Control Events and Performance
There were ten control events initiated in 2013. The date, time and estimated impact for each
event is provided in Table 9.
Tabie I
lrrigation Load C.ontrol Events
*Amps and Camas Subs excluded from dispatch
Evaluation
Performance of the Idaho Irrigation Load Control programs is contained in Appendix 6.
Pe ak RU&i8ti61t?t8 #dllt
Estimated Load
Reduction - Idaho at Gen
(MW)
6/18/13
7118113
7l25tr3 9
Page l6 of43
Rocky Mountain Power
Exhibit No. 1 Page 324 of495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Re sIff Bitti 5lFrb!flJtrfs
EtEn<;t' Ept tcuixct' PRoGRA\{s
Energy efficiency progrcms are offered to all major customer sectors: residential, commercial,
industrial and agricultural. The overall energy efficiency portfolio includes six programs: Home
Energt Saver - Schedule 118, Residential Refrigerator Recycling- Schedule ll7, Low Income
Weatherization - Schedule 21, FinAnswer Express - Schedule 115, Agricultural Energy Services
- Schedule 155 and Energ,, FinAnswer - Schedule 125. Program savings and cost results for
2013 were provided in Table 3. Additional program information is provided below.
Krisl ntst"r[ dr, X]Rt;cft.AaI s
The residential energy efficiency portfolio is comprised of three programs, Home Energy Saver,
Residential Refrigerator Recycling and Low Income Weatherization. As shown in Table 10, the
residential portfolio was cost effective based on four of the five standard cost effectiveness tests
for the 2013 reporting period. The ratepayer impact test was less than 1.0 indicating that there is
near term upward pressure placed on the price per kilowatt-hour given a reduction in sales.
I tll')|.' I ll
Lr:st. ir{-ibttir,eness itrr ltesidential iiort iirli,'
I BenefiUCost
I Ratio
i Net Benefits
I
I
Total Resource Test olus $6r4,95s l
Total Resource Cost Test s435,742
:i--$-r-r-3 C
$2,8 14,578 I
i Rgle:qy*"-tl1pgsl 0.45 i ($1,803,42e) i
["] c nee Ex crl;,, 5'{rlsr Progra nt
The Home Energy Saver program is designed to provide access to and incentives for more
efficient products and services installed or received by customers in new or existing homes,
multi-family housing units or manufactured homes for residential customers under Electric
Service Schedules I and 36. Program participation by measure is provided in Table I 1.
Iabl* i I
[,1igiclc []iogran': \'leasurcs t L,nits)
Measures 2013 Total
Units
2013 Total r 2013 kWh
Participants , @ site
$l 3s6,781
Central A.iC Equipment
66.833
225 , 9,s30I Dishwasher
Page 17 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 325 of 495
Case No. PAC-E-14-07
Re sYff g?tti 5f tHbgf tJfl fs
2013 Total
Participants
2013 kwh
@ site
Drictless Heat Pump 56,000
Electric Water Heater 2,569
Floor Insulation 9.237
Gas Furnace 2.640
Ground Source Heat Pump Conversion l? 5?s
Heat Pump System Conversron 10,332 l
Heat Pump Water Heater 3,524
Refrigerator s.269 i
Room AC 1.599
Wall Insulation ) )\)3.386
I
2,420\,
Lighting - CFL General 59.629 i
Lighting - CFL Specialty 18 I 413.142 )
Grand Total 396.066 , 11.020 2.512.467 I
Program performance results for January I " 2013 - December 31 ,2013 are provided in Table 12.
I ahie ll
i.ili"tt-t:rnr Cost Eil:ctii'clrcss iirl I"[onrc F.n,:r'rr Salcr Pr(]granl
2013 TotalMeasures I -":].'"
' unlts
4t 4: 1,708
Benefit/Cost
Ratio
Net jBenefit/Costl Net
Benefits , Ratio Benefits
t nr_!y/-g ],t9!=!grq:benefi* ',, Excluding !g!-"1:!sy b_g!"fi!t_,
: 1 -- : ^-^-^^^ I r ^r I ^^-^,^^ IiTotalResourceCostTestplus l0percent j 1.66 i $726.220 i 1.24 $263,502 ]i Total Resource Cost Test 1.54 $60r,741 Lll-r---$112P21
Utilitv Cost Test $419.33s l r .5 r $4 r 9.335
Participant Cost Test 3.27 $2.1 14.020
I Rate Payerlmpact ) 0.49 ($1,284,893) I 0.49 , ($1,284,893)
Program Management
The program manager who is responsible for the Home Energ,t Saver program in Idaho is also
responsible for the Home Energt Saver program in California, Utah, Washington and Wyoming
and the Refrigerator Recycling program in Idaho, California, Utah, Washington, and Wyoming.
For each program and in each state the program manager is responsible for the cost effectiveness
of the program, identifuing and contracting with the program administrator through a
competitive bid process, establishing and monitoring program perforrnance and compliance, and
recommending changes in the terms and conditions set out in the tariff.
Page 18 of43
Roclq Mountain Power
Exhibit No. 1 Page 326 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Re sl&etiti 5f 'p{bEflJffis
Proeram Administration
The Home Energlt Saver program is administered by PECI. PECI, a private non-profit
corporation, has been designing and implementing energy efficiency programs since 1990.
PECI is responsible for the following:
o Retailer and trade ally engagement - PECI identifies, recruits, supports and assists
retailers to increase the sale of energy efficient lighting, appliances and electronics. PECI
enters into promotion agreements with each lighting manufacturer and retailer for the
promotion of discounted compact fluorescent lighting ("CFL"). The agreements include
specific retail locations, lighting products receiving incentives and not-to-exceed annual
budgets. Weatherization and HVAC contractors engaged with the program are provided
program materials, training and receive regular updates.
o lnspections - PECI recruits and hires inspectors to verify on an on-going basis the
installation of measures. A summary of the inspection process is in Appendix 7.o Incentive processing and call-center operations - PECI receives all requests for
incentives, determines whether the applications are completed, works directly with
customers when information is incorrect and/or missing from the application and
processes the application for payment.
o Program specific customer communication and outreach A summary of the
communication and outreach conducted by PECI on behalf of the Company is outlined in
the Communication, Outreach and Education section.
Infrastructure
The Company, through its third party vendor, is working with 22 retailers to promote CFLs and
light-emitting diodes ("LEDs"). Table l3 lists the lighting retailers participating in the program.
' ^ llI flDlt- i -r
Retail Stores * i-ishtinu
Store Name
Ace Hardware #14355
: Ace Hardware#9479 Saint Anthony
BMC West- Rexburg Rexburg
Broulim's Fresh Foods #l
Broulim's Fresh Foods #2 Rexburg
Broulim's Fresh Foods #3
'8 To be considered for participation for discounted CFLs and LEDs, sales coming from the Company's customers
must be a significant majority of total sales.
Page l9 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 327 of495
Case No. PAC-E-1+07
ResYffEttti5fHbtAJnre
Store Name CFLs I LPot
Dollar Tree #3691 Rexburg {l
Downey Food Center Downey
Mickelsens #2 Rexburg
Platt Electric Supply #53
Platt Electric Supply #54
Pocatello
Idaho Falls J {
Platt Electric Supply #88 Rexburg
Thomas Market Inc. #l Malad City I I
Twenty three local and national retailers now consistently promote high efficiency appliances on
behalf of the program. Table l4le lists the retailers where customers can purchase program
qualifoing appliances for program incentives.
True Value #101l9 Preston
True Value #10217 I Montpelier
i True Value #1064 Malad City
1 True Value #1654 Rexburg
True Value #5448 I Terreton
True Value Hardware - CAL Ranch Stores Rexburg
Walgreens #9918 Rexburg
Walmart #1878 Rexburg
Wolfe Lighting Rexburg
'l'airle l4
Ilereil Sl<ires * Appiiances
i
!
i
:
:
I
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ii .loi
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=i():-E'-,-8.@u'o:olTlr
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Ace Hardware #14355 i Rexburg
Ace Hardware #9479 i Saint Anthony
Best Buy #944 : Idaho Falls i.iin
Bingham & Sons Fumiture and Appliance i Rexburg .vi{
Blacker's Home Furnishings I Idaho Falls
Denning's Showcase I Idaho Falls i{i{
Do It Best - Stronks and Sons : Ashton
Do It Best - Yellowstone ' Rigby
El Gene's TV and Appliance i Rexburg nt.v
re Check mark indicates retailer participation during 2013
Page20 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 328 of 495
Case No. PAC-E-1+07
Re sYff Bltti 5?'FIbEf Ufl fS
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I falls Rlumbing Supply i Idaho Falls
I First Sreet Plumbing Idaho Falls
i Home Depot #1802
i Lowe's #1906 Idaho Falls
i Northgate Appliance Idaho Falls
i Rocknacks Hardware Plus
' Sanders Fumiture Soda Springs
t Sears #2278
Thomas Electric & Fumiture Malad City
I True Value #10217
U&I Furniture
Wolfe Lighting #l
Table 15 and Table 1620list the HVAC, weatherization and window contractors.
'I"able 1 5
ll\:A(' ( cntraclors
i Alpine Heating Idaho Falls
j Conan Heating Idaho Falls
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'o Check mark indicates retailer participation during 2013
Page 2l of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 329 of 495
Case No. PAC-E-1+07
ResXfrBlttiSlqbtsFJafs
Trade Allv Name Ci
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First Call Jewel, Inc Idaho Falls {i
Hallmark Exteriors Ammon l
Holeshot Plumbing Ammon
i Johnson Brothers Idaho Falls I
Malad Heating and
Cooling LLC
Malad
Citv
Master Tech LLC I nieuy
I Palmer Heating and
: Coolins LLC Idaho Falls :
i
Quantum Group Idaho Falls i
Sprinter Heating and
i Young Electric, Heating
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I rblc lt,
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I Advanced Insulation Idaho Falls I 'V
Page2? of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 330 of495
Case No. PAC-E-1+07
ResY[gtttiSfEbgltJtrtr
Classic Remodeling
Clearwater Custom Carpentry , L.*irton :, dt Lonstructlon I
t1i Eco Insulation i Blackfoot I !
ldaho Falls j
Hansen Paint & Glass
Newt Construction LLC I Idaho Falls
I Go Green Insulation Caldwell
Pocatello
iRockyMountainlnsulation _r Pocatello ir/ , I i i
Demographics
Approximately 64 percent of all Home Energy Savers incentive applications in 2013 were
received from customers located in Idaho Falls, Rigby, Rexburg, and Ammon. Table 17
summarizes customer applications by city.
T:rlrl,. , -
{ ustome:,tpplicai,irl b"r' l.ir,.
City
oh of Total -
Appliance &
Fixture
Applications
Yo of Total -
HVAC
Applications
% of Total -
Weatherization
Applications
Yo of Total -
All
Applications
IDAHO FALLS 25.80o/o 27.30o/o 12.50%25.30o/o
RIGBY 14.600/o 3.00o/o 7.80%14.10%
REXBURG 12.80o/o 6.10o/o 32.80o/o 13.40Yo
AMMON 11.10o/o 18.20%15.60Yo ll.40o/o
SHELLEY 5.20o/o 9.10o/o 6.30o/o 5.30o/o
PRESTON 4.50o/o 0.00%9.40%4.600/o
SUGAR CITY 2.600 0.00%3.10o/o 2.60%
SAINT ANTHONY 2.20%3.00o/o l.60Yo 2.20o/o
IONA 1.80o/o 0.00%0.00%1.70Yo
MALAD CITY l.40Yo 3.00o/o 0.00%t3a%
Page23 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 331 of495
Case No. PAC-E-1+07
ReslffEittibfqblAJmfS
City
% of Total -
Appliance &
Fixture
Applications
% of Total -
HVAC
Applications
%o of Total -
Weatherization
Applications
% of Total -
All
Applications
ASHTON 1.30o/o 0.00%0.00%t.20%
FIRTH 1.00%9.10%0.00%t.t0%
UCON 0.80%3.00Yo 3.10o/o l.00Yo
45 Additional Cities <10
Evaluation
During 2013, a process and impact evaluation was initiated by a third party evaluator for
program years 2011-2012. The process and impact evaluation was completed in first quarter of
2014.
R efri ge rata r R. e cyc I ing
The Refrigerator Recycling program, also known as "See ya later, refrigerato@," is designed to
decrease electricity use through voluntary removal and recycling of inefficient refrigerators and
freezers for residential customers served on Electric Service Schedule 1. Participants receive a
$30 incentive for each qualifuing refrigerator or freezer recycled through the program and an
energy-saving kit which includes two CFLs, a refrigerator thermometer card, energy-savings
educational materials, and information on other efficiency programs relevant to residential
customers.
Program participation by measure is provided in Table 18.
'{"able IS
f,ligibtre Preigranr \4easi-rrcs (( jnits I
Program performance results for January 1,2013 - December 31,2013 are provided in Table 19.
PageZ4 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 332 of 495
Case No. PAC-E-14-07
ReslffBtttiSfqblFJffiS
l"ahie
[-ong-tenn Cost Etfectiveness
lq
for I{.efii gerator i{ecl,clirig
I Rate Payer Impact I 0.48 , ($149,359) |
In2013, more than 73,580 pounds of metal, 11,320 pounds of plastics, and l,3ll pounds of
tempered glass were recycled as a result of the program. In addition, the capture, recovery or
destruction of more than 737 pounds of ozone depleting Chlorofluorocarbons (greenhouse gases)
and Hydro fluorocarbons, commonly used in refrigerants and foam insulation equates to
approximately 2,143 metric tons of carbon dioxide.
Program Management
The program manager who is responsible for the Refrigerator Recycling program in ldaho is also
responsible for the Refrigerator Recycling program in Califomia, Utah, Washington and
Wyoming and Home Energt Saver program in Idaho, California, Utah, Washington, and
Wyoming. For each program and in each state the program manager is responsible for the cost
eflectiveness of the program, identifuing and contracting with the program administrator through
a competitive bid process, establishing and monitoring program performance and compliance,
and recommending changes in the terms and conditions set out in the tariff.
Proeram Administration
The Refrigerator Recycling program is administered by JACO Environmental ("JACO"). JACO
started over 20 years ago in Snohomish County, north of Seattle, Washington, JACO has grown
to become one of the largest recyclers of house-hold appliances in the United States. The
Company contracts with JACO to provide customer scheduling, pick-up, incentive processing
and marketing services for the program.
JACO's process ensures that over 95 percent of the components and materials of the discarded
appliance are either recycled for beneficial uses or eliminated in an environmentally responsible
way. The remaining 5 percent can then be productively used as oofluff' to facilitate the
decomposition of biodegradable landfi I I material.
JACO is responsible for the following:
. Appliance handling - JACO handles all customer and field service operations for the
program including pick-up of refrigerators and freezers from customers, transporting the
units to the de-manufacturing facility and recycling of the appliances.
Total Resource Cost Test plus l0
Total Resource Cost Test
2r Participants in See ya later, reft'igeraro@ program incur no costs.
Page 25 of 43
Rocky Mountain Power
Exhibit No. 1 Page 333 of495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report ReslffBltti5f'HbEfHffs
o Incentive processing and call-center operations - Customer service calls, pick-up
scheduling and incentive processing are handled by JACO.. Program specific customer communication and outreach - Working in close coordination
with the Company, JACO handles all the marketing for the program. The program is
marketed through bill inserts, customer newsletters and TV, newspaper and online
advertising.
As part of the program control process, the Company contracts with a third-party independent
inspector to conduct ongoing oversight of the program's appliance recycling process, from
verification that the units being recycled meet the program eligibility criteria to verifying they
are being recycled and that the program records are accurate.
A summary of the inspection process is included in Appendix 7.
Infrastructure
A crew from Salt Lake City, Utah, picks up units collected through the program in Idaho and
transports the units to a JACO facility in Salt Lake City for disassembly and recycling.
Evaluation
In October 2013, a process and impact evaluation was completed by a third party evaluator for
program years 2011-2012. The impact evaluation provided data on the gross realized savings and
the Net-to-Gross ('NTG") ratio. The process evaluation investigated participant satisfaction,
implementation and delivery processes, marketing methods and quality assurance. The
Company's response to the recommendations and web link to the evaluation report are included
in Appendix 8.
tr-ol, I nc o nr e Vl'e u the ri $tti $ u
The Low Income Weatherization program provides energy efficiency services through a
partnership between the Company and local non-profit agencies to residential customers that
meet the income-eligible guidelines. Services are at no cost to the program participants.
Program participation and number of homes receiving specific measures in 2013 are provided in
Table 20.
T'able 20
Homes Receiving Specifi c [\4easures
Panicioation - Total # of Comoleted./Treated Homes 74
Number of Homes Receivins Specific Measures
Attic Ventilation 23
Ceiline lnsulation 26
Page26 of 43
Rocky Mountain Power Idaho Report
Roclry Mountain Power
Exhibit No. 1 Page 334 of 495
Case No. PAC-E-1+07
Re sYff gitti 5t'HbE+Ufl fs
Compact Fluorescent Light Bulbs 68
Duct Insulation r9
Floor Insulation 20
Fumace Repair 34
Health & Safety Measures 26
lnfiltration 47
Refrigerators 3
Reolacement Windows 38
Thermal Doors 3s
Wall Insulation 6
Water Heater Repair 6
Water Pipe Insulation 58
Program performance results for January 1,2013 - December 31,2013 are provided in Table 21.
Table I1
Cost Eiiccti:,eness lcr [.or,' Income \.\'eatherizalion
As shown in Table 21, the Low Income Weatherization program ex-ante results suggest the
program was not cost effective based on the five standard cost effectiveness tests for the 2013
reporting period. This is largely due to a decrease in number of homes served and measures
installed by over 28 percent from the program's 2012 program results and a decrease in the
Company's avoided costs.22 All applicable and identifiable non-energy benefits recommended
in Order No. 32788 were applied. The Company is investigating possible program
improvements while awaiting the results of the 2014 program evaluation before making a
determination on what broader actions will be necessary to ensure program cost effectiveness
going forward.
ProETam Management
The program manager who is responsible for the Low Income Weatherization program in Idaho
is also responsible for the Low Income Weatherization program in California, Utah, Washington
and Wyoming; energy assistance programs in Idaho, California, Oregon, Utah, Washington and
Wyoming; and bill discount programs in California, Utah and Washington. The program
manager is responsible for the cost effectiveness of the weatherization program in each state,
" The 2Ol3 Integrated Resource Plan filed in March, 2013, generated lower avoided costs for energy efiiciency
resources than the value previously provided in the Company's 201 I Integrated Resource Plan and used in the
calculation of the program's economics in the 2012 annual report.
Total Resource Cost Test
($80.763)
| (S239,519)
Page27 of43
Rocky Mountain Power
Exhibit No. 1 Page 335 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Re sXff EittiSf 'Hb!f,Jfl fS
partnerships and agreements in place with local agencies that serve income eligible households,
establishing and monitoring program performance and compliance, and recommending changes
in the terms and conditions set out in the agency contracts and state specific tariffs.
Program Administration
The Company currently has contracts in place with Eastem Idaho Community Action Partnership
("EICAP") and SouthEastern Idaho Community Action Agency ("SEICAA") to provide services
through the low income weatherization program. These two agencies receive federal funds
allocated to the Idaho Department of Health and Welfare ("IDHW") and administered by the
Community Action Partnership Association of Idaho ("CAPAI") through subconffacting non-
profit agencies. Energy efficiency measures are installed in the homes of income eligible
households throughout the Company's service area by EICAP and SEICAA. Company funding
of 85 percent of the cost of approved measures is leveraged by the agencies with the funding
received by IDHW.
By contract with the Company, EICAP and SEICAA are responsible for the following:
o Income Verifrcation - Agencies determine participants are income eligible based on
CAPAI guidelines. Household's interested in obtaining weatherization services apply
through the agencies. The current income guidelines are included in Appendix 9.. Energy Audit - Agencies use a United States Department of Energy approved audit tool
to determine the cost effective measures to install in the participant's homes (audit results
must indicate a savings to investment ratio of 1.0 or greater).o Installation of Measures - Agencies install the energy efficiency measures.o Post Inspections - Agencies inspect 100 percent of completed homes. IDHW and
CAPAI also inspect a random sample of homes. See Appendix 7 for verification
summary.o Billing Notification - Agencies are required to submit a billing to Company within 120
days after job completion. The agencies include a form indicating the measures installed
and associated cost on each completed home along with their invoice.
Evaluation
The Low Income Weatherization program will be evaluated in 2014 by Smith & Lehmann
Consulting. This firm was selected through an RFP process and will complete the evaluation by
the end of2014.
Low lncome Energ, Consefl,stion Educstion
Commission Order No. 32788 dated April 12,2013, ruled that the Company's funding of Low
Income Energlt Conser-vation Education should be $25,000 annually. These services are
provided by EICAP whose main office is located in Idaho Falls, ldaho, and SEICAA whose
main office is in Pocatello, Idaho. They target the Company's customers that receive Low
Income Home Energy Assistance ("LIHEAP") funds. EICAP, SEICAA and the Company staff
discussed the allocation of the annual funding amount and the agencies determined the efficiency
Page28 of 43
Rocky Mountain Power
Exhibit No. 1 Page 336 of495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report Re sIff Eltti 5f 'FVUEIHffiS
measures they wanted to distribute. These measures were discussed with Commission staff.
EICAP received $13,250 and SEICAA $11,750 foratotal of $25,000 priorto the beginning of
their 2013/2014 LIHEAP program year. While the conservation education activities do result in
energy savings, the savings are not considered when calculating the performance results of the
Low Income Weatherizationprogram, other energy efficiency programs or portfolios results.23
The agencies provided a conservation education curriculum to households and reported the
following activities and program specifics for 2013:
Eastern Idaho Communitv Action Partnership
Number households served: 679
Number kits distributed: 679
Cost of each kit: $19.50/kit, S13,240.50 in total
Items in kits: I showerhead, 1 window insulation kit, l0 outlet gaskets, l0 switch plate gaskets,
rope caulk, I compact fluorescent light bulb (20 watt), I compact fluorescent light bulb (13
watt), 1 refrigerator thermometer, I hot water temperature card, 1 bath aerator, I kitchen aerator,
I night light, Teflon tape and 1 air filter whistle
Program design: Educate the Company's customers on how to conserve energy and understand
their bill.
Target audience: The Company's customers receiving energy assistance.
Gauge program's success in meeting goals: Acceptance of energy conservation tools after
education.
Indicate how Company funds are used: Purchase items that encourage energy conservation.
Describe how the progrcm benefits participants: Households receive useful tips and tools to help
them save energy while applying for LIHEAP.
SouthEastem Idaho Communitv Action Agency
Number households served: 128
Number old kits distributed: 75
Number of new measures distributed: shower timers :27,night lights : 26
Cost of new measures: shower timers : $2.63 each, night lights = $2.95 each, total cost incurred
of new measures purchased: $7,681.30
Program design: Reduce electricity usage and monthly bills for participants of the LIHEAP
program.
23 Order No. 32788
Page29 of 43
Rocky Mountain Power
Exhibit No. 1 Page 337 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report ResffiElttifiHbEfHflfS
Target audience: LIHEAP recipients that have not had weatherization program services as a
high priority. Households can also be identified through SEICAA's other programs. The
Company may refer customers for possible participation using current LIHEAP income
guidelines as the first criteria.
Gauge program's success in meeting goals: The program's success will be gauged through
periodic reporting and the response from the participants through surveys.
lndicate how Company funds are used: To purchase energy conservation measures (energy
saving night lights and shower timers). Funds are also used for educator salaries.
Describe how the program benefits participants: Households are educated on how they can
reduce kWh usage through behavioral changes as well as the installation and benefits of the
energy conservation measures they receive during LIHEAP intake.
SEICAA is continuing to distribute kits purchased from the Company funding provided in 2010.
These kits include I compact fluorescent light bulb (13 watt), I compact fluorescent light bulb
(19 watt), I compact fluorescent light bulb (23 watt), l0 outlet gaskets, 1 kitchen aerator, I
refrigerator temperature card and I night light. As of 12/31/13 they have 106 old kits yet to
distribute.
Page 30 of43
Rocky Mountain Power
Exhibit No. 1 Page 338 of495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report Commercial and InUtISffi 5f 'p{t!fldfltr
Coultinc[Ar- AND INnt srnrAr, Pnocnanls
The commercial and industrial energy efficiency portfolio is comprised of three programs,
FinAnswer Express, Agricultural Energy Services and Energt FinAnswer. The commercial and
industrial portfolio was cost effective based on four of the five standard cost effectiveness tests
for the 2013 reporting period, as provided tnTable 22.
lrlrle ll
Cosi [il'eciivcness ior C]ourmerciai and Iniiustrizrl Partliilio
i Utility cost Test $2,244,985
Fi$-4trswcr Erpres-v
The FinAnswer Express program is designed to help commercial and industrial customers
improve the efficiency of their new or replacement lighting, HVAC, motors, building envelope,
and other equipment by providing prescriptive or pre-defined incentives for the most common
efficiency measures listed in the program incentive tables.2a The program also includes custom
incentives and technical analysis services for measures not listed in the program incentive tables
that improve electric energy efficiency. The program provides incentives for both new
construction and retrofit projects, and is designed to operate in conjunction with the Energy
FinAnswer program. Program participation by measure group is provided in Table 23.
'tr'ahic 13
Instal ieii []16gram h,'ieasures i:rplr]iua,ilrr.r i
Measure Groups 2013 Total
_Building Shell 2
I Compressed Air r 2 1
l*Peir.y-Igg!-qulprn94----- - lo---i
r Food Service
] HVAC 6:Lighting 99
ilryg.a. T"tal I 123 i
2a Incentive tables can be found online at
https://www.rockymountainpower.net/content/dam,/rocky_mountainjower/dociBusiness/Save_Energy_MoneyllD_
FinAnswerExpress_Brochure_Retrofit.pdf for retrofi ts and
https://www.rockymountainpower.net/content/dam,/rocky_mountain_power/doc/Business/Save_Energy_Money/ID_
FinAnswerExpress_Brochure_NCMR.pdf for new constructioll./major renovation projects
Benefit/Cost ; Net BenefitsRatio i
i Total Resource Test olus l0
Total Resource Cost Test
Page 31 of43
Rocky Mountain Power
Exhibit No. 1 Page 339 of495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report commerc ial and InHlIsff i5f HtEFJflffi
Program savings by measure group is provided inTable 24.
-fable l4
Insialied Prograrn h4easLrres (gross k\\'hl'ear at site)
Program performance results for January 1,2013 - December 31,2013 are provided in Table 25.
I rtLr:r --
Cost Efleci iven*ss io r F i n A ns"r'cr l--.x 1:rress
Proelram Management
The program manager who is responsible for the FinAnswer Express program in Idaho is also
responsible for the FinAnswer Express program in California, Utah, Washington and Wyoming
and the Agricultural Energy Services program in Idaho. For each state the program manager is
responsible for the cost effectiveness of the program, identifying and contracting with the
program administrators through a competitive bid process, program marketing, establishing and
monitoring program performance and compliance, and recommending changes in the terms and
conditions of the program.
Prosram Administration
The program is primarily marketed through local trade allies who receive support from one of
two program administrators hired by the Company. The Company contracts with Nexant, [nc.
("Nexant") and Cascade Energy ("Cascade") for trade ally coordination. training and application
processing services for commercial and industrial/agricultural measures respectively.
Nexant and Cascade are responsible for the following:
2013 Total
, Total Resource Test plus l0
Total Resource Cost Test
Participant Cost Test
Page32 of 43
Rocky Mountain Power
Exhibit No. 1 Page 340 of 495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report C omm erc i al and I nUl5Sff i 5f Hb!flJfl fS
o Trade ally engagement - Nexant and Cascade identifu, recruit, train, support and assist
trade allies to increase sales and installation of energy efficient equipment at qualiffing
business customer facilities.o Incentive processing and administrative support - Nexant and Cascade handle incoming
inquiries as assigned, process FinAnswer Express incentive applications, develop and
maintain simplified analysis tools and provide program design services, evaluation and
regulatory support upon request.
o Inspections - Nexant and Cascade veriff on an on-going
measures. Summary of the inspection process is in Appendix 7.
In addition, the Company's project managers coordinate FinAnswer Express projects and
provide customers with program services and incentives using the energy engineering
consultants described further in the Energy FinAnswer program section.
Infrastructure
To help increase and improve the supplier and installation contractor infrastructure for energy-
efficient equipment and services, the Company established and developed trade ally networks for
lighting, HVAC and motors. This work includes identifuing and recruiting trade allies, providing
program and technical training and providing sales support on an ongoing basis. The current list
of the trade allies who have applied and been approved as participating vendors are posted on the
Company website and included as Appendix l0 to this report. Customers are not required to
select a vendor frorn this list to receive an incentive.
The total number of participating tr:ade allies is cun'ently
trade allies by technology is in Table 26.
The current count of participating
Tabic 26
Ilartic i pati ng T'racie ..tl lies
ofthe
i Ligirting trade allies I HVAC trade allies ii--ll Motor and VFD
Itrade allies i
List dated 41312013 28
Evaluation
ln February 2013, a process and impact evaluation was completed by a third party evaluator for
program years 201 1-2012. The impact evaluation provided data on the gross realized savings and
the NTG ratio. The process evaluation investigated participant satisfaction, implementation and
delivery processes, marketing methods and quality assurance. The Company's response to the
recommendations and web link to the evaluation report are included in Appendix 8.
" Some trade allies may participate in more than one technology so the count of unique participating firms is less
than the total count by technology.
29
Page 33 of43
Rocky Mountain Power
Exhibit No. 1 Page 341 of495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report commercial and InHlSffi5ftF{btf,Jntr
A 5;ric u l t u r al,Sx ergp',Sen'icss
The Irrigation Energt Savers program is designed to improve the overall energy efficiency of
irrigation systems by promoting energy efficient irrigation practices and the installation of
energy efficient measures for customers on Schedule 10 and who qualiff as a 'oFarm Load"
under the Pacific Northwest Electric Power Planning and Conservation Act, P.L. 96-501. The
program also complements the Inigation Load Control program by focusing on improving the
efficiency and management of these seasonal loads.
In an effort to address the "high degree of uncertainty regarding the program energy savings"
identified through third party evaluations, the Company filed to revise Schedule 155 -
Agricultural Energy Services to suspend: (1) the Nozzle Exchange Program; and (2) incentives
for the pivot and linear equipment measures listed in the tariff on May 24,2013 (Case No. PAC-
E-13-10). The Commission approved the request in Order No. 32879, effective August 15,2013.
The 2013 program included the following:
Equipment exchange - Provides new standard brass sprinkler nozzles, gaskets, and drains
to replace worn equipment on hand lines, wheel lines and solid set sprinklers systems.
This offer ended effective August 15,2013.
Pivot and linear equipment upgrades - Incentives were provided for certain pivot and
linear system measures including sprinkler packages, pressure regulators, and drains. The
list of prescriptive incentives that were available until August 15, 2013 was not designed
to be exhaustive and other pivot measures are eligible for incentives if energy savings can
be calculated and the customer incurs costs to make the changes.
System consultation - This service provides a simple site specific audit of a customer's
irrigation system to promote irrigation water management and identify energy savings
opportunities. This consultation provides information prior to a full pump test.
Pump testing - The pump test includes directly measuring pump lift, flow, electrical
demand, and system pressures and is performed after the pump has been screened and the
owner's financial investment criteria understood.
System Analysis - The program provides energy engineering to help growers quantify
the costs and savings of their system efficiency upgrades. Often these upgrade decisions
are made in conjunction with operational production change considerations impacting a
growers equipment needs. Incentives are based on a standard formula tied to costs and
first year energy savings.
A summary of the program savings by measure group for 2013 is provided inTable 27.
l,rtal"5 rI
lnstalled ProEran-r h,teasures (rorr ,..1tr']"rryear at sile)
Page 34 of 43
Rocky Mountain Power Idaho Report
=- n, o o X,""lY I""#i1! :'"X"J
Case No. PAC-E-1+07
c o mmerc i al and InHtIB,ff i5f Htgf ldtrtr
Program performance results for January 1,2013 - December 31,2013 are provided in Table 28.
The cost eflectiveness for the system redesign measure group is being provided to show its
results in support of Order No. 32879 that was approved August 15,2013.
'fablc l8
Cost [l-fbctiveness {cr Aericultura[ l:nergv Sen'ict-s
Net Benefits
Prosram Level
;f-o-9"!*Re.9ogr_cgTe$ p$Llgprlggnt :_ _ _o_2_?_ __i __$-?_l2J Lq
I Total Resource Cost Test i O.t+ I ($+SS.ZS+
2.43 i $ 1,544,965
s1.305.992
I Utllltv Cost l'est $289, r 67
i Particioant Cost Test 0.86
0.78 s904,624 2.39
The results for TRC plus l0 percent and the TRC are not cost effective at the program level
which was expected. The Company encountered an increase of nozzle exchanges and pivot and
linear equipment upgrades as a result of qualifying customers learning of the application filing
submitted with Commission for program changes.
Program Management
The program manager who is responsible for the lrrigation Energt Savers program in Idaho is
also responsible for the FinAnswer Express program in Idaho, Califomia, Utah, Washington, and
Wyoming. For each program and in each state the program manager is responsible for the cost
effectiveness of the program, identiffing and contracting with the program administrators
through a competitive bid process, program marketing, establishing and monitoring program
performance and compliance, and recommending changes in the terms and conditions set out in
the tariff.
Proeram Admini strati on
Benefit/Cost i Net BenefitsRatio i
BenefiVCost
Ratio
The program was primarily marketed through
serving local irrigators. These efforts in 2013
Nexant.
irrigation specialists, trade allies and retailers
were supported by the program administrator,
The Company contracted with Nexant to provide trade ally coordination and application
processing services for Irrigation Energt Savers pro$am. Nexant was responsible for the
following:
Trade ally engagement - identiff, recruit, train, support and assist trade allies to increase
sales and installation of energy efficient equipment at qualifuing customer site.
Incentive processing and administrative support - handle incoming inquiries as assigned,
process incentive applications and provide program design services, evaluation and
regulatory support upon request.
$ 1,948.1 l2r.00 $6.471
Page 35 of43
Rocky Mountain Power
Exhibit No. 1 Page 343 of495
Case No. PAC-E-1+O7
Rocky Mountain Power Idaho Report C ommerc i al and InHtISffi 5f 'p{b$8flff
Inspections - verify equipment installation on a sample basis for Equipment Exchange
and every installation for System Analysis.
Engineering analysis - provide site specific engineering as required by the program for
System Analysis.
Infrastructure
To help increase and improve the supplier and installation contractor infrastructure for energy-
efhcient equipment and services, the Company developed trade ally networks for irrigation
equipment. The current lists of the trade allies who are participating vendors are posted on the
Company website26.
Evaluation
In May 2013, a process and impact evaluation was completed by a third party evaluator for
program years 201 l-2012. The impact evaluation provided data on the gross realized savings and
the NTG ratio. The process evaluation investigated participant satisfaction, implementation and
delivery processes, marketing methods and quality assurance. The Company's response to the
recommendations and web link to the evaluation report are included in Appendix 8.
Energy Fin-4nstver
The Energt FinAnswer program is offered to all non-residential new construction, retrofit
commercial (buildings 20,000 square feet and larger) and industrial customers. The program is
designed to target comprehensive projects requiring project specific energy savings analysis and
operates in concert with the more streamlined FinAnswer Express program. The program
provides Company-funded energy engineering, incentives of $0.12 per kilowatt hour ("kWh")
for first year energy savings and $50 per kilowatt of average monthly demand savings, up to a
cap of 50 percent of the approved project cost. In addition to customer incentives, the program
provides design team honorariums (a finder fee for new construction projects) and design team
incentives for new construction projects exceeding International Energy Conservation Code
("IECC") 2009 energy code by at least 10 percent.
Projects completed by sector during 2013 are provided in Table 29.
http://www.rockymountainpower.net/content/dam/rocky_mountain_power/doclBusiness/Save Energy_Money/Irrig
ation_Energy_S avers_Participating_Dealers.pdf
Page 36 of 43
Rocky Mountain Power
Exhibit No. 1 Page 344 of495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report C ommerci al and InUtISff i5f 'pfblflflfS
Program savings by measure group is provided in Table 30.
-l able 3()
lnstalleij Jrrofralr1 h.4easures {gr()ss l,\\'h,'r'ear at site)
Measure Grou 2013 Total
Additional Measures
Program performance results for January 1,2013 - December 31,2013 are provided in Table 3 I .
"I'ahl.; 1 I
L.,:ii g-'ie;'rl C o* Li'l't'cti vencss iirt l-nct'gr l':i t-i.{nsr.t cr
Benefit/Cost
Ratio
Net
Benefits
I Utilitv Cost Test 3.74 $899,530
*!p.t!slpq!_cej!Is$2.64 $r.067.703
i Rate Payer Impact ' 0.73 ($450,728)
Program Management
The program manager who is responsible for the Energt FinAnswer program in Idaho is also
responsible for the Energ,, FinAnswer program in Califomia, Utah, Washington, and Wyoming;
the Self-Direction program in Utah and Wyoming; and the Commercial & Industrial Re-
Commissioning program in Utah. The Company employs five full-time project managers" in
support of the program manager.
The Energt FinAnswer program is administered by the Company. Consequently, the program
manager is responsible for the following:
a
a
Program cost effectiveness and performance
Ensuring the program is operated in compliance with commission tariffs and Company
guidelines including but not limited to qualification of customers
Customer communication and ouffeach
Monitoring code and standard changes
o
a
27 Based on the volume of projects, temporary project managers and/or support staff are employed from time-to-time
236.902
Controls 362.311
HVAC 337.755
27.684
97,846
949,422
327
2.339.279
Total Resource Cost Test
Total Resource Cost Test 1.74 $521,821
Page37 of43
Rocky Mountain Power
Exhibit No. 1 Page 345 of 495
Case No. PAC-E-14-07
Rocky Mountain Power Idaho Report Commercial and InHtl5ffiSftp{b!f,JflfS
o Qualification of materials and equipmento Engineering analysis of customer opportunities
o Quality control and assuranceo Customer service, including the delivery of services and incentiveo Verification of installation and savings2s
The program is marketed primarily via the Company's customer and community managers, trade
allies, Energy FinAnswer consultants and project staff. Other leads come via advertising in
business publications, company newsletters, word-of-mouth, past participants returning for
additional projects and a combination of other Company outreach efforts.
Infrastructure
Given the diversity of the commercial and industrial customers served by the Company, a pre-
approved, pre-contracted group of engineering firms are used to perform facility specific energy
efficiency analysis, quality assurance and verification. This being said, the individual projects are
directly managed by one of the Company's project managers. The project manager works
directly with the customer or through the appropriate community and customer account manager
located in Idaho. Table 32 lists the engineering firms currently under contract with the Company.
I able -12
f nEiueei'ing F irnrs
Engineering Firm Main Office Location
i Abacus Resource Mangge*ent Company BeaBeaverton, OR
rIi Brendl,e Qroup _Fort Collins, CO
tQeqee&llgrry-E:e:Ilgerqe ! Cedar Hills, UT
faglpr.sri", E"gi"ee i Salt Lake City, UT
i Ecova Portland, OR
I gMP2. tnc - iSjgblatt{J4
L-Erersv:Bs'"eq{g.-I!qe-sl_erggyBSq9qrqe_In!e_gryE9t*W______1_lppelit_o,_C4
LElgltr-erqBeleuresjelsleu I North Andover, MA
I EnerNOC Inc.
I EnSave. I
ETC [ncorporated
Eve Consul
Fazio
tl-al t !*"ss_ltL!t______*r' Beaverton, OR
Weston, OR
i kW Engineerin Inc.Salt Lake Ci UT
i vEr EngrBy rvranagtrrilerrL, ulu. E eavEr ruil, \Jr\ I
i RM Energy Consulting j Pleasant Grove, UT
EIE M OR
i Rick Rumsey, LLC
i SBW Consu WA
ltqrq{e & E4gry9nqg'IrL.,--,,E-vgsttg. 9_Bi 9o-! ars Argbitp:lue4lleryesle Is
Gfplglg,.t Elglg
Bell
Salt Lake Citv, UT
" Summary of inspection process is in Appendix 7.
r Portland, OR
Page 38 of43
Rocky Mountain Power
Exhibit No. 1 Page 346 of 495
Case No. PAC-E-1+07
Rocky Mountain Power Idaho Report Commercial and InHtlSffibftHb!flJffiS
Evaluation
In February 2013, a process and impact evaluation was completed by a third party evaluator for
program years 201 l-2012. The impact evaluation provided data on the gross realized savings and
the NTG ratio. The process evaluation investigated participant satisfaction, implementation and
delivery processes, marketing methods and quality assurance. The Company's response to the
recommendations and web link to the evaluation report are included in Appendix 8.
Page 39 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 347 of 495
Case No. PAC-E-14-07wgdhffitutrrtdtf8lt
ColrvurlcATloxs, Ou'rntr.+cu AND Enuclrrox
The Company utilizes earned media, customer communications, paid media and program
specific media in an effort to communicate the value of energy effrciency, provide information
regarding low-cost, no-cost energy efficiency measures, and to educate customers on the
availability of technical assistance, services and incentives. The overall goal is to engage
customers in reducing their energy usage through behavioral changes as well as changes in
equipment, appliances and structures.
ldaho Eanted tr{edia
Earned media is managed by the Company's communications department in cooperation with the
company's customer and community managers in Idaho. The company identified one news story
in20l3 that mentioned its energy effrciency programs (there may be additional news stories not
posted online):
o lllSll3 - Idaho State Joumal: Rocky Mountain Power proposes credit for Idaho
customers early next year
http://rrywv.idahostatejournal.coni/nelvs/local/rocky-mountain-power-proposes-credit-
for-idaho-customers-earl.v---nexVarticle a2ce9262-48d5- I I e3-9b8c-001a4bcf887a.lrtml
The company distributed three news releases to media in Idaho during 2013 that included
information about its energy efficiency programs:
9/19113 - See yaLater, Refrigeratorr. 2013 Refrigerator Roundup is underway
https ://u.mv.rock)rmouritainpower.nettabout/nrlnr20 1 3lslrrru. html
1l/8113 - Rocky Mountain Power proposes credit for Idaho customers early next year
https:rlrwvrv.rockrrn-rountainporver.ireVabout/nr/m'20 I 3/rock]:mountainJ:owerproposesc
red itlbridahocu stomersearl vnextyear.htrnlc 12/2113 - Idaho communities shine during Rocky Mountain Power's Refrigerator
Roundup
https://rvrryrv.rockymountainpower.netiaboutinr/nr20I3licsdrmprr.htmi
Ctt sto m e r Corn m u n icctti o tt s
As part of the Company's regular communications to its customers, newslefiers across all
customer classes promote energy effrciency initiatives and case studies on a regular basis. Inserts
and outer envelopes featuring energy efficiency messages and progtams have also been used on a
consistent basis. In2013, the Company also issued two newsletters focused entirely on seasonal
energy efficiency information targeted in the fall and spring.
The Company also utilizes social media, such as Twitter and Facebook to communicate and
engage customers on DSM offers and incentives.
Page 40 of43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 348 of495
Case No. PAC-E-1+07wie6tufi1tlfr1ftdtfmr
Program Speci.{ic
All energy efficiency program marketing and communications are under the wattsmart umbrella
to ensure a seamless transition from changing customer behavior to the actions they could take
by participating in specific programs. Separate marketing activities administered by and specific
to the programs ran in conjunction with the wattsmart campaign.
Home Energv Savings program
The Home Energt Savings program communicates to customers, retailers and trade allies
through a variety of channels. A new program brochure was developed, which highlights the
benefits of energy-effrcient appliances and equipment and lists the incentives available in Idaho.
In addition, a sales kit folder with marketing materials was used by program field staff as a
resource for retailer and trade ally engagement.
ln the summer, program
included:o Point ofpurchaseo Handout materialo Web featureso Bill inserto Social media
communications focused on cooling measures. The cooling campaign
materials
for retailers and trade allies to use in their sales to customers
A similar heating campaign was developed for the fall and winter, including:
o Web featureso Sales handout and outreach to trade allieso Bill insert and incentive check insert
o Email. Social media
In November, program communications emphasized the deep discounts and incentives available
for the GE GeoSpring Hybrid Water Heater. This ofler was communicated to Idaho customers
via newsletters, email, website and social media.
To make it easier for customers to submit and track online applications, program staffworked to
enhance the system to allow customers to upload electronic receipts and other documents. Other
improvements were also made to the online system for appliance and lighting applications.
Residenti al Refri eerator Recyclin g
The Company promotes its See ya later, refrigerator@
other customer communications. In April and May
impressions through digital display ads and paid search.
program through digital advertising and
2013, the program garnered 270,000
Page 4l of43
Rocky Mountain Power Idaho Report
Roclry Mountain Power
Exhibit No. 1 Page 349 of 495
Case No. PAC-E-1+07wiedhftttfrlftdtfmr
Inserts promoting the See ya later, rffigerato@ program went out in February, April and
September bills. In addition, a postcard was sent in February to customers who had recently
purchased a new refrigerator and received an incentive through the Home Energlt Savings
program.
From August through October, the Company promoted the "refrigerator roundup" to Idaho
customers and reported the communities that recycled the most refrigerators and freezers during
this time through news releases, social media and on the website.
FinAnswer Express and EnergllFinAnswer
During 2013 communications continued to emphasize the change in federal lighting standards
that took place July 14, 2012. This standard applies to manufacturers of general service
fluorescent lamps. Spring radio ads encouraged customers to retrofit their older linear fluorescent
lighting and thoCompany added a video2e and retained a page3o on the website dedicated to this
topic. The program's breakdown of impressions by media type is shown in Table 33.
"l'ahie 3i
lmpt'essicx"ls h-r, N'1*4', typ*
Communications Channel
Aericultural Energy Services
The Company promotes the Agricultural Energy Services program at key events and reaches out
directly to participating customers and dealers when there are updates or changes to the program.
Communication activities during 20 I 3 included:
o Letter with Irrigation Hotline brochure was mailed on March 21,2013, to Idaho irrigation
customers to inform them about upcoming changes to the Irrigation Load Control
program and introducing EnerNoc, our contractor overseeing the program.
o Letter and frequently asked questions mailing on May 31, 2013, to Idaho irrigation
customers to inform them about requested changes to the Irrigation Energy Savers
program, effective August 15,2013. The changes affected incentives fornozzles, gaskets
and drains as well as pivot and linear system upgrades.
2e rvwrv.rockJ.'mountainporver. neUidsave
30 www.rockl-mountairrpower.rret,/[ i ghtin gstarrdards
2013
200,229
I 35.897
Page 42 of 43
Rocky Mountain Power Idaho Report
Rocky Mountain Power
Exhibit No. 1 Page 350 of 495
Case No. PAC-E-1+07
wtness: ESAnfitlUm
Ev,tLuertoN*s
Evaluations are performed by independent extemal evaluators to validate energy and demand
savings derived from the Company's energy efficiency programs. Industry best practices are
adopted by the Company with regards to principles of operation, methodologies, evaluation
methods, definitions of terms, and protocols including those outlined in the National Action Plan
for Energy Efficiency Program Impact Evaluation and the California Evaluation Framework
guides.
A component of the overall evaluation efforts is aimed at the reasonable verification
installations of energy efficient measures and associated documentation through review
documentation, surveys and/or ongoing onsite inspections.
Verification of the potential to achieve savings involves regular inspection and commissioning of
equipment. The Company engages in programmatic verification activities, including inspections,
quality assurance reviews, and tracking checks and balances as part of routine program
implementation and may rely upon these practices in the verification of installation information
for the purposes of savings verifications in advance of more formal impact evaluation results. A
summary of the inspection process is included in Appendix 7.
Evaluation, measurement and verification tasks are segregated within the Company's
organization to ensure they are performed and managed by personnel who have a neutral interest
in the benefits associated with anticipated savings.
Information on evaluation activities completed or in progress during 2013 is summarized in the
chart below. Summary of the recommendations are provided in Appendix 8. The evaluation
report i s available at vvrvr,r,. pac i fi co rp. c ornie sldsm/i daho. htm l
of
of
Program / Activities Years Evaluated Evaluator Progress Status
See ya later, refrigerator@ 2011-2012 The Cadmus Group Completed
FinAnswer Expess 2009-2011 Navigant Consulting, Inc.Completed
Irrigation Energy Savers 2009-2011 Navigant Consulting, lnc.Completed
Energy FinAnswer 2009-2011 Navigant Consulting, Inc.Completed
Home Energy Savings 2011-2012 The Cadmus Group QI of2014
Low-Income 2010-2012 Smith & Lehmann In Progress
Page 43 of43
Rocky Mountain Power
Exhibit No. 1 Page 351 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POWHR
A DIVIS}ON OF PACIRCORP
20t3
.,n, ontllY LiT:1! :,"ffJ
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Energv Efficiency Programs
The MW reported savings of 3.44 (at generation) for energy efficiency programs during 2013
represents the summation of estimated MW values made available through the Company's
business and residential energy efficiency programs; calculations for the business and residential
programs differ.
The Company's business programs MW contributions are based on engineering estimates of
capacity values for installed measures; project unique factors are individually calculated for
custom projects while deemed factors are utilized for prescriptive measures. These calculations
are based on actual installed measures in the reported year. For 2013, it is calculated that 2.41
MW of capacity contribution were made available through business program energy efficiency
acquisitions. Specific hours during which business program measures contribute MW capacity
are dependent upon several factors including specific business operations and general economic
conditions.
For the residential programs, an energy to capacity factor is utilized to calculate the MW savings
made available through these programs. The energy to capacity factor utilized in the calculation
(2.46 MW in 2013 for each average MWh of energy efficiency acquired) is the same as the
average load profile factor of energy efficiency resources selected in the 2013 IRP, i.e. the
average peak contribution of the energy efficiency resource selections across all measures and
sectors. The utilization of this factor in the MW calculation assumes that the energy efficiency
resources acquired through the Company's residential programs have the same average load
profile as those energy efficiency resources selected in the 2013 IRP. Utilization of this factor in
determining the MW contribution of energy efficiency programs for 2013 is detailed in the table
below.
Line Description Value
First year EE program savings acquired during 2013 3,686
2 Average MWh value (line I I 8760 hours)0.42
aJ Peak MW contribution of 2013 EE acquisitions l.04
As demonstrated, it is estimated that the residential energy efficiency program acquisitions in
2013 contributed 1 .04 MW of capacity contribution. As with the business programs, when these
savings occur on an hourly basis is dependent upon several factors including energy usage
patterns of residential customers.
Together, the 2.41 MW's estimated for the business programs and the 1.04 MW's estimated for
residential programs make up the 3.44 MW savings value of energy efficiency programs.
Rocky Mountain Power
Exhibit No. 1 Page 353 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
YH,ffi:OUNTAIN
Appendix2
Idaho Cost Effectiveness
Roclry Mountain Power
Exhibit No. 1 Page 354 of 495
Case No. PAC-E-1+07
Vurtness: Kathryn C. Hymas
Table of Contents
PortfolioandSectorLevelCostEffectiveness......'...........
Program Level Cost Effectiveness.................. ...............6
Home Energy Savers Program...... .........6
Refrigerator Recycling (See ya later, refrigerator@)........ ..............9
Low lncome Weatherization - Schedule 21 ........... ....................11
FinAnswer Express ..........13
Agricultural Energy Services (lrrigation Energy Savers) ..............15
Energy FinAnswer - Schedule 125............... ...........18
Page 2 of 19
Rocky Mountain Power
Exhibit No. 1 Page 355 of 495
Case No. PAC-E-1+o7
\Mtness: Kathryn C. Hymas
Portfolio and Sector Level Cost Effectiveness
The tables below present the cost-effectiveness analysis for the Idaho DSM Portfolio based on
Rocky Mountain Power's 2013 costs and savings estimates. Individual program cost-
effectiveness is provided in the following pages.
Table I lists the utility sector-level inputs. Table 2 lists the portfolio costs, Table 3 through Table
5 provide the cost-effectiveness results for:
. Idaho 2013 Total DSM Portfolio, Including Non-Energy Benefits
o Idaho 2013 C&I DSM Portfolio, Including C&l Evaluation Costs
o Idaho 2013 Residential DSM Portfolio, lncluding Residential Evaluation Costs and Non-
Energy Benefits
The overall energy efficiency portfolio and component sectors were cost effective on a
PacifiCorp Total Resource Cost Test (PTRC), Total Resource Cost Test (TRC), Utility Cost Test
(UCT), and Participant Cost Test (PCT) basis.Table 1. Portfolio Utility Inputs
Discount Rate 6.88%
Residential Line Loss
Commercill Lile Losp
Industrial Line Loss
Irrigation Line Loss
Residential Energy Ratg ($/kWh) (base ye,,ar 2013)
Commercial Energy Rate ($/kWh) (base year 2013)
Indrytrilf.Ener_gy R1.q ($/kwh) (!ase xgur !013)
fnigqtion Energy Ra-te ($/kWh) (base year 2013)
Inflation Rater
I Future rates determined using a 1.9Yo annual escalator.
tt.47y:o
10.7sYo
7.5204
11.45%
$0.1 062
$0.088s
$0.0689
$0 0898
1.90%
Page 3 of 19
Rocky Mountain Power
Exhibit No. 1 Page 356 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Total Resource Cost
Test (PTRC) +
Conservation-Adder
Total Resource Cost
Test (TRC) No Adder
Utility Cost Tes!- (UCT)
Rate Impact Test (RIM)
Participant Cosi Test
(PCr)
Lifecycle Revenue
Impacts ($lkWnl
Commercial & Industrial Evaluation
Costs
Residential Eval uation Costs
Technical Reference Library
DSM Central
Low Income weattreiiiation Portfol io
C9-s-ts
Total
$0.079 $6,690,405
$0.079 $6,690,405
$0 056 $4,794,085
$12,639,711
$6,476,925
$73,655
$ 129,658
$23,705
$ 13,566
$25,000
sios,is+
s8,444,627
$7,692,854
$l,zi:o,tzo
$7,977,986
$ 12,605,285
$0.000096705
$1,754,222
$1,002.449
$2,436,051
/\.r hAi 'lt
$6.128,360
1.26
1.15
1.51
b'o:
1.95
'['able 2. Fortfolio Cosfs 3{}13
'Y*\'ylt 3. Xelak* ?t!tr3 "t'ota} {}S}'t Portfolio Cost-Etfecfiveness Results
{ tncl ud! ng Nolt-Euerg3, Benef}ts}
Discounted Parlicipant
Payback (years)2.96
Page 4 of 19
Rocky Mountain Power
Exhibit No. 1 Page 357 of 495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
$6,298,157 $1,201,537
$0.078 $5,096,620 $5,725,597 $628,978 1.12
Table 4.ldaho 20t3 C&I DSi\{ Portfolio Cost-Eff'eetiveness Results
(lncluding C&l Evaluation Costs
Utility Cost Test (UCT)$0.053 $3,480,612 ', 55,725,597 $2,244,985 1.64
. Partic,ipant cost Test
$ 5,546,717 $g,g60,499 $3,3r3,7g2, 1.60(!cq,
Lifecycle Revenue
Impacts ($lkwh) 0'000081373
Discounted Participant 4.94
: PeyP-eSt."(y-.g*-ry)
Total Resource Cost
Test (PTRC) +
Conservation Adder
$0.078 $1,531,514 52,t46,470 $614,955 1.40
Table 5. Idaho 2013 Residential DSkl Portfolio Cost-Eff'ectiveness Results
(Ineluding Residential Evaluation Costs and Non-Energl, Benefits)
Total Resource Cost
Utility Cost Test (UCT)
, -S31"_." 1T-p-3"_t Ig'(W)'-_
Participant Cost Test
$0.078 $1,531,514 , $1,967,256 $435,742
$253,336
$3,307,967 $1,504,538 r$i.8().1.{2(}r
$930,209 53,744,787 $2,814,578
1.28 ,re_e1(l$c_)_N.-"_*9-{p"r
1.20
0.45 .
4.03(PCr)
Lifecycle Revenue $0.000037411tqpagts ($(y_!)
Discounted Participant
Payback (years)0.99
Page 5 of 19
Rocky Mountain Power
Exhibit No. 1 Page 358 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Program Level Cost Effectiveness
Home Energy Savers Pr*grarn
The tables below present the cost-effectiveness results for the Idaho Home Energy Savers
program based on Rocky Mountain Power's 2013 costs and savings estimates. The utility
discount rate is from the 2013 PacifiCorp Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2013 IRP east residential house 35o/o load factor
decrement for all measure groups except for lighting, for which the 2013 IRP east residential
lighting 48oh deuement was used. Table 1 lists the utility inputs. Table 2 lists the annual
program costs. Table 3 shows the annual energy savings and measure lives. Table 4 shows the
annual program non-energy benefits. Table 5 provides the cost-effectiveness results including
non-energy benefit. Table 6 provides the cost-eflectiveness results excluding non-energy
benefits. The Home Energy Savings program was cost-effective from all perspectives except for
the rate impact test (RIM).
Discount Rate 6.88%
R;id;ii, Lil.i;'; 1.4j%
Residentiil ene.gy Rate ($/kWh) (base year 201 3) $0.1 062
Inflation Ratet l.g}%
i irtr.. i"i". J.t.rrir"J using a 1.9o/o annual
"r.utuio.."
-['able 4. FIonre Enersv Savinss Annual Prosram Costs
APPlil'l.g:
HVAC
$l3,sal.
"
$3,1 16
$114,9.59
_
$26,455
$274?233
$19,225
$40?j73:3
$48.796
$354,673
$82,102
$298,730
$194,697
I-iglrting
Weatherization
$-2,1e6
$13,478
$18?646 ,
$ I 14.431
$82,862
$142,307
$l03,70:
$270,2t6
l'abtre 3. lfonre Energv Savings Utilitv Inputs
Total s32,332 9274,491 $518,627 $825,450 $930,209
Page 5 of 19
Rocky Mountain Power
Exhibit No. 1 Page 359 of 495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
324,480
iti,,i,tt
1,421,855
87%326,744 30
1,672,771
375,567 100%375,567
2,512,467 2,512,467
Table 6. [Iorne Energ3' Savi Annual Non-Ene
Clothes Washer
Table 5. Home En
377 ??0?
86,827
Anrrual Ene
r $nnli-a19tt. HVAC
377t30?
86,827
860/o
860/o
,Lighting
, Wgalhefzatlg-l
; Total 2,147,750
$20,445 PTRC,TRC, PCT
Total Resource Cost
Test (PTRC) +
Conservation Adder
$0.068 $1,105,762 $1,831,982
C.lL G.eleral *rp,9l:
CFL Specialty
$58,020 PTRC,TRC, PCT
$21,5I1 PTRC,TRC, PCT
s726,220
Tatrle 7. Honre Energl,Savings
Cost-Effectiven ess Res ults (I ncl u din g Non-Energv Ben efi ts)
Total Reso
Test (TRC
urce Cost
) No Adder $0.068 : $1,105,762 $ 1,707,503 $601,741 1.54
_J_f i_[!y -cost ]!1 q_gf )"-
-R19 Jm"nacl-l:.1 G{\{) .
Participant Cost Test
$825,450 $1,244,786 $419,335$0.0s 1 1 .51
.... .$2:129{7?
$930,209
st,244,786 ($1.:84.891)0.49
s3,044,229 $2,114,020 3.27(PCr)
Lifecycle Revenue
Impaclg ($/kw!)$0.000026654
Discounted Participant 1.13pav_Qeq!,(yg?Il)
Page 7 of 19
Rocky Mountain Power
Exhibit No. 1 Page 360 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
T'abEe 8. I'trome Energ_v Savings
Cosf-Effectiveu ess Results (Exclu c[i n g N olr -En v Benefits)
Total Resource Cost
Test (PTRC) +
Conservation Adder
Total Resource Cost
Test (TRC) Ng Adder
__U-_tility gosl rest.(ucl) .n*: If-pq:1 res! (|!!)
Panicipant Cost Test
(PCT)
Lifecycle Revenue
Impacts ($/kWh)
Discounted Participant
Payback (years)
$0.068. $1,105,762 $1,369,264
$0.068 $1,105,762 $1.244,786
$0.051 $825,450 $t,244,796
, . s2,s/?:67e ..$!.?44,786
$0.0000266s4
1.58
$263,502
$139,023
$419,335
i$-1,2.e1,8031
$1,571,911
1.51
o:4g
2.69
1.24
Page 8 of 19
Rocky Mountain Power
Exhibit No. 1 Page 361 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Refrigerator Recycling [See ya later, refrigerator@)
The tables below present the cost-effectiveness results for the ldaho See Ya Later Refrigerator@
(SYLR) program based on Rocky Mountain Power's 2013 costs and savings estimates.
Cost-effectiveness was tested using the 2013 IRP east residential house 35o/o load factor
decrement for refrigerators and freezers and the 2013 IRP east residential lighting 48Yo load
factor decrement for kits. Table 1 lists modeling inputs. Table 2 lists annual program costs. Table
3 provides the annual energy savings and measure lives. Table 4 shows the program cost-
effectiveness results. The program is cost-effective from all perspectives except for the RIM.
6.89:/"
11.47%
$0.1062
t.soi),
s7,230 $39,543 $7,566 $67,448
$2, I 06 $11,517 $2,204 $3,870 $ 19,697
$306
Refriser-a!9p
Freezers
-..Krts s292 $ 1,599
Total $9,628 $52?659
$3r011
$19,991
$5,208
$92,353 .$10,075
Tnble 3. SY-LR. Annual Ener Savin
Refriggrators
Freezers
520,030
134,289
.860/.o
97%
447,226
130,260
24r,s110'2
62,525
54%
48%
7
)
Table
T*ble SYLR Annual
Kits
Total
38:48,9
692,799
47%18.,996
595,572
100%1q,ggg
322?ttz
6
Page 9 of L9
s0.047 $92,353 $150,452 $58,099
Rocky Mountain Power
Exhibit No. 1 Page 362 of 495
Case No. PAC-E-1+07
VMtness: Kathryn C. Hymas
1.63
Total Resource Cost Test
(PTRC) * Conservation
Adder
Total Resource Cost Test
(TRC) No Adder- uiiiity cmi rlJ tucrl
$0.047
$0.047
$92,353 $136,774
$136,774
s44,421
$44,421
1.48
1.48$92,353
$286, I 33 $136,774 ($ l4e,35q)Rate lmpact Test (RIM)0.48
Participant Cost Test
(PCr)$0 $377,135 $377,135 N/A
Table 4. SYLR Frogram Cost-Effectiveness Results
Lifecycle Revenue $0.000007506Impacts ($/kwh)
Discounted Participant N/APayback (years)
Page 10 of 19
Rocky Mountain Power
Exhibit No. 1 Page 363 of495
Case No. PAC-E-1+07
VMtness: Kathryn C. Hymas
Low Income Weatherization - Schedule 21
The tables below present the cost-effectiveness results for the Idaho Low Income Weatherization
program based on Rocky Mountain Power's 2013 costs and savings estimates. The utility
discount rate is from the 2013 PacifiCorp Integrated Resource Plan (lRP).
Cost-effectiveness was tested using the 2013 IRP east residential house 35Yo load factor
decrement. Table I lists the utility inputs. Table 2 lists the annual program costs. Table 3
provides the annual energy savings and measure life. Table 4 shows the program's non-energy
benefits. Table 5 shows the program cost-effectiveness results. The program is cost-effective
only from the participant cost test (PCT) perspective.
Discount Rate
nesiaeniiat til;il';-'
Residential Enerry Rate ($/kWh) (base year 2013)
Inflation Rater
' Future rates determined using a l.gYoannual escalator.
6.88%
1t_47%
$0.1062
1.90%
Inccme Weatherizntion
Page 11- of 19
Table 2. Low,{ncome Weat}rerization Annual ram Costs
Rocky Mountain Power
Exhibit No. 1 Page 364 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
s164,667 $203,741Low lncome
Ie3lrerp1i91
Table 3. Low Incor*e lYeatherization Annual Enersv Savin
Low Income
Weatherization
I:rblo 4. Low Income \1,'eatherization: Prosent \/ulue of l\on-li 'BenelIts
$28,760 PTRC
(PTRC) * Conservation $0.1 43 $203,741 $164,036 (S30.;1151
Adder
Total Resource Cost Test $0.1 43 s203,741 $122,978 ( $1t0.76i i.gB,c)No Adder 0.60
Table 5. Low Income Weatherization Cost-Effectiveness Results
Total Resource Cost Test
Utility Cost Test (UCT)$0.1 43 $203,741 $122,978 { $1r0.761i
$362,497 $122,978 i$1iQ ilQr
$323,423 $323,423
0.60
0.34
N/A
$0.000005332
N/A
Page 12 of 19
Rocky Mountain Power
Exhibit No. 1 Page 365 of 495
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
FinAnswer Express
The tables below present the cost-effectiveness results for the Idaho FinAnswer Express program
based on Rocky Mountain Power's 2013 costs and savings estimates. The utility discount rate is
from the 2013 PacifiCorp Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2013 IRP east system 70o/oload factor decrement. Table
I lists the utility inputs. Table 2 lists the annual program costs. Table 3 shows the annual energy
savings and measure lives. Table 4 provides the cost-effectiveness results. The program was
cost-effective from all perspectives except for the rate impact test (RIM).
Discount Rate 6.88%
10.7504Commercial Line Loss
lndustrial Line Loss 7.52%
Commercial Elerry,Rate ($/kwh) (base year 2013)
lndustrial Energy Rate ($/kWh) (base year 2013)
f"nutio, nu,"
$0.088s
so.oosq
1.90%
' Future rates determined using a 1.9%o annual escalator.
Table X0. FinAnswer Exnress Annual ranr Costs
Commercial
Industrial
Total
$52,352 $23,288 $155,334
"siz,:t4--q1gj;j , . qou;
$'65,266 $4W91 I $215,556
$353,933, $597,379 i $1,043,566s12,472
$39,1 18
Table 1tr. FinAnswer Express Annual Ener Savin
$26,646 $2_61f:s
$615,788
$.38q:14.9 $99lljl
$977,519 $1,651,697
Commercial
Industrial
Total
. -2:297_,5:04
3,148?539
5J56,043
101% 2,229,579 67%1,493,818 12
- lol%r 3,190,02-4
5,409,603
67o/o 2,130,616 12
t,ii,+,iiii
T'able 9. FinAnswer Express lJtility,' trnputs
Page 13 of 19
Table 12. FinAnswer ress Cost-Effectiveness Results
$0.04s $1,468,368 $2,318,209 $849,841
$0.04s $ I,468,368 $2,107,463 $639,095
Roclry Mountain Power
Exhibit No. 1 Page 366 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
1.58
1.44
$0.030 $977,519
$ 1,651,697
$2,107,463 $1,129,944
$3,474,481 s2,107,463 i$1.367.(tl8r
-2:1-6
0.61
$-4r312j:_?7
$0.00004597s
$2,690,900 2.63
2.62
Page 14 of 19
Rocky Mountain Power
Exhibit No. 1 Page 367 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Agnicultural Energy Services {Irrigation Enerry SaversJ
The tables below present the cost-effectiveness results for the Idaho Agricultural Energy Savers
program based on Rocky Mountain Power's 2013 costs and savings estimates. The utility
discount rate is from the 2013 PacifiCorp Integrated Resource Plan (IRP).
Cost-effectiveness was tested using the 2013 IRP east commercial cooling 20Yo load factor
decrement. Table I lists the utility inputs. Table 2 lists the program costs. Table 3 shows the
annual energy savings. Table 4 lists program cost-effectiveness results. Table 5 lists the system
redesign cost-effectiveness results. The Agricultural Energy Savers program was cost-effective
only from the utility cost test perspective (UCT). The system redesign measure group is cost-
eflective from all perspectives.
Irrigation Energy Rate ($/kWh) (base yiar '
2013)
Inflation Rater
' Future rates determined using a 1.9oh annual escalator
Table l. L;tilitv Asricultural Ene , Savers Inouts
Page 15 of L9
Rocky Mountain Power
Exhibit No. 1 Page 368 of495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
ricultural *inergv Savers Annual Program Costs
Equipment
Exchqnge
Pivot/Linear
Upgradg
System
R-e{esign
Total
5,234.47 68,008.80
15,541.09 201.917.59
4,649.85 $48,538
13,805.38 $381,260
$41,404
$897,420
$992.073
0.92
0.84
1.14
;;
0.86
133.939.50 1,825.98 23,724.00 1,622.04 $280,508
$126,431
$612,524
$441,620
$133,940 522,602 $293,650 s20,077 $710J07 $1,180,575 $1,930,897
57%Equipment
Exchange
Pivot/Linear
Upgrade
System Redesign
Total
Total Resource Cost
Test (PTRC) +
Conservation Adder
fotd neiource Cost
Test (TRC) No Adder
443,942 ,
**.
4,584,301 '
2,293300
7,321,543
(0.71)
1.69
$0.201 $2,848,015
$0.201 $2,848,0 I 5
so.r+q $2,100,564
(3,254,854)
3.875,677
620,823
57% (1,855,267)
qi,ii/,i ii,6,oq;8a
1,749,113
r tl I Q : I r ) ).- } \.i
($458.28+;
$289,167
5
5
7
'tr'ahle .{" Asrricll}rurn{ Encr Savers Ccst*Ef{'ect! venesx Restxlts
Utility Cost Test (UCT)
$2,628,705
$2,389,731
si,Eg,g,331
Rate Imga3l Test (RIM)
Participant Cost Test
(PCr)
Lifecycle Revenue
Impacts ($/kWh)
Discounted Parlicipant
Payback (years)
s4,042,206
s3,242,915
$3,1 37,582
$2,798,093
$0 000045463
N/A
:'tut'rr/,'.iltJ L "v-,l
1 (J.L i !l' rt+ i
Tahle 3. Agricultural Energv Savers Annual Energv S*vin
Page 16 of 19
'["able 5. Asricultura] ].Savers Svstem ltedes
Rocky Mountain Power
Exhibit No. 1 Page 369 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Cost-}]ffectiveness Results
Total Resource Cost i
Test (PTRC) +
Conservation Adder
Total Resource Cost
rgqt (rR!) Nq A{de1
Utility Cost Tesr (UCT)
Rate lmpact Test (RIM)
Participant Cost Test
$0.047
$0.047
qo:ole
$ 1,083,740
$ 1,083,740
$441,620
$2,383,261
$2,628,705
$2,389,731
$2,389,731
sz,:sq,i:l
sl,544,965
$ 1,305,992
$1,-e19,11-2
$6,471
2.43
2.21
i;i
r.00
2.39,ec_I)
Lifecycle Revenue
Impacts ($/kwh)
$992,073 $2,368,294
($;0.00()0(10325 )
$1,376,221
Discounted Participant
Payback (years)2.12
Page 17 of 19
Rocl{y Mountain Power
Exhibit No. 1 Page 370 of495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
Energy FinAnswer - Schedule 1ZS
The tables below present the cost-effectiveness results for the Idaho Energy FinAnswer program
based on Rocky Mountain Poweros 201 3 costs and savings estimates. The utility discount rate is
from the 2013 PacifiCorp Integrated Resource Plan (IRP).
Cost-eflectiveness was tested using the 2013 IRP east system 70o/oload factor decrement. Table
1 lists the utility inputs. Table 2 lists the annual program costs. Table 3 shows the annual energy
savings and measure lives. Table 4 provides the cost-effectiveness results. The program is cost-
effective from all perspectives except for the rate impact test (RIM).
Discount Rate
Commercial Line Loss
Industrial Line Loss
Commercial Energy Rate ($&Wh) (base year 2013)
Industrial Energy Rate ($/kWh) (base year 2013)
lnflation Ratel
' Future rates determined using a l.9Yo annual escalator.
6 8!o/o
10.75%
7.52%
so.osss
$0.0689
1.90%
Table Energl FinAnsvver
T:rblc i.1" SLnerg3, Fi*A*srver" .&nxrtxrli Frosralm Cascs
Cgmmgrc!al
Industrial
$e,i21
$70,726
$8,932
$1 1,769
q3:3J4. $s2:92s, .574,625
$22,014 $149,740 $254,249
$J 06,3-53
ss45,752
Total
c,qrp:"lqiul
Induslrial
Total
$80,120
a]s,20-;,s.
1,914,074
$20,701 $25388 $202,665 $652,105
n"ahle !5. Energy Fi*.A*swer Annu*i Energv Savi*
89%
89o/o
811(
83%
3s?,92::o
1,588,681
31!:9ee_
1,413,926
1,941,602 1,728,025'2,339,279
Page 18 of 19
Rocky Mountain Power
Exhibit No. 1 Page 371 of495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Total Resource Cost
Test (PTRC) +
Conservation Adder
$0.039 $706,582 $1,351,243 $644,662
Table 16. Energt, FinAnslver C*st-Effectiveness Results
Total Resource Cost
Test (TRC) No Adder $0.039 $706,582 sl,228,403 $521,821 1.74
Utility Cost re{ (Ujr)
Rate Impact Test (RIM)
Participant Cost Test
(PCT)
Lifecycle Revenue
Impacts ($/kWh)
Discounted Participant
Payback (years)
$0.018 $328,873
$1,679,.131
$652,1 05
$t?2-.28,403
$1,228?49?
$ 1,719,808
$0.0000131 18
5.+)
3.74
0.73
2.64
$899,530
($150.728)
$1,067,703
Page 19 of 19
Rocky Mountain Power
Exhibit No. 1 Page 372 of 495
Case No. PAC-E-1+07
VVrtness: Kathryn C. Hymas
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Case No. PAC-E-14-07
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Exhibit No. 1 Page 425 of 495
Case No. PAC-E-1+07
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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Exhibit No. 1 Page 427 ol 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
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Exhibit No. 1 Page 428 of 495
Case No. PAC-E-1+07
Vvitness: lGthryn C. Hymas
ROCKY M
POWER
A DIVISION OF PACIRCORP
OUNTAIN
Appendix 5
ENERNOC Irrigation Load Control Report
OrruERNoc
Roclry Mountain Power
Exhibit No. 1 Page 429 of 495
Case No. PAC-E-1+07
\ fitness: Kathryn C. Hymas
ROCKY MOUNTAIN
PO\TUER
A Mffi OT HC#IMiP
OENERNoc
YH,ffiE^H:O'NTAIN
201I PacifiCorp lrrigation had
Control Program Report
EnerNOC, lnc
One Marina Park Dr, Ste 400
Boston, MA 02110
www.enernoc.com
Rocky Mountain Power
825 NE Multnomah St, Ste 550
Portland, OR97232
www.pacificorp.com
Date:
March 3,20t4
Confide ntial and Proprietary Poge 1
Roclry Mountain Power
Exhibit No. I Page 430 of 495
Case No. PAC-E-14-07
\y'Vitness: Kalhryn C. Hymas
OEr'trnrcoc V,ROCKY MOUNTAINxfrpowun
!IDUE&#mFrftiP
Contents
Overview of the 2013 lrrigation Load Control Program ....,....................3
Review of 2013 enrollment and enablement.............. ...........................4
Customer outreach ...........4
Provider payment structure..... .............4
Enrolled customers ...........5
EnerNOC site servers ........5
Legacy devices........ ...........6
Technical challenges .........6
Data quality challenges.. .......................7
Review of 2013 program performance ...........8
lmpacts of pay-for-performance model ...................8
lmpact of crop type............ .................10
lmpact of irrigation technology and water availability.. .............11
Geographic se9mentation.................. .....................11
Weekly available load reduction............... ..............12
Load controlevents....... ......................13
Customer satisfaction and issues... -........................L7
Key lessons learned from 2013... ..................18
Enrollment and retention ................. ......................18
Enablement ..............,......19
Dispatch mana9ement.................. ......20
Confidential a nd Praprietary Page 2
Rocky Mountain Power
Exhibit No. 1 Page 431 of 495
Case No. PAC-E-14-07
Orru=RNoc povt ER
A ONEft OF MT'M'
Overview of the 2OL3Irrigation Load Control Program
This report provides an overview of PacifiCorp's lrrigation Load Control Program in the Rocky Mountain
Power (RMP) service territory, as implemented and administered by EnerNOC. EnerNOC and RMP are
pleased with all that the program accomplished in 2013, including a large-scale transition to a new
business model and technology platform over a compressed timeframe. This report is intended to
document program results, accomplishments, and challenges, including lessons learned and, where
applicable, plans for 20L4.
PacifiCorpselected EnerNOCto managethe irrigation load control(lLC)program beginning in 2013and
through 2022. EnerNOC's responsibilities include enrollment, equipment installation, dispatch
management, performance calculations, and customer service. Along with program management
changes, the performance measurement and incentive structure changed substantially from previous
years. A new pay-for-performance structure rewards irrigators for the value they provide during
program hours, versus peak monthly capacity. lmportantly, under this construct PacifiCorp only pays for
capacity available during program hours, as measured by EnerNOC's energy monitoring technology and
adjusted through a performance factor to account for those sites which opt not to participate during
specific dispatch events. ln order to achieve this incentive structure, interval metering was necessary.
EnerNOC's equipment solution provides 5-minute interval energy monitoring as well as remote
irrigation equipment control. EnerNOC's web-based portal now provides irrigators and PacifiCorp with
near real-time energy usage data.
The motivation for these program changes was to develop a sustainable program that meets the needs
of irrigators, the utility and ratepayers overthe long-term. ln January and February 20L3, RMP and
EnerNOC met and collaborated with various stakeholders to explain the program changes and refine the
program offeringto bettermeetallparties'needs. The ldaho lrrigation PumpersAssociation (llPA)and
Utah Farmers Bureau provided valuable feedback about program incentives and rules. Regulatory
approval was achieved in ldaho and Utah in mid-March 2013.
The ILC program is currently available to Tariff Schedule 10 customer sites in the Rocky Mountain Power
(RMP) ldaho and Utah service territories. ln future years, participation may expand to customers in
Oregon, California and Washington. Participating sites are compensated for shutting off irrigation load
for specific time periods determined by RMP, and are provided day-ahead notice of dispatch events.
Customers always have the opportunity to opt out of (i.e., choose not to reduce load) for dispatch
events as necessary for their operations. Customer incentives are based on a site's average available
load during load control program hours adjusted for the number of opt outs or non-participation. The
program hours are 12 to 8pm Mountain Time (MT), Monday through Friday, and do not include
holidays.
The 2013 program season ran from Monday, June 10 through Friday, August L6. Average weekly
available load reduction was 120.9 MW. RMP utilized forty of the fifty-two possible program event
hours. There were ten load control events, each four hours in length, which will be described in more
Vvitness: Kathryn C. Hymas
ROCKY MOUNTAIN
Co nfide nti a I a n d P ropri etary Page j
Rocky Mountain Power
Exhibit No. 1 Page 432 of495
Case No. PAC-E-1zt-o7
Vvitness: Kathryn C. Hymas
OrruERNoc aF,;RACKY MOUNTAINIgPoi/ER
!rommclmmr
detail below. On average the program delivered 115.6 MW of actual load reduction compared to
baseline load (determined as usage on the day prior to the dispatch) of 137.0 MW. This actual load
reduction is calculated according to 5-minute interval data from EnerNOC's energy monitoring
equipment. As a result load not monitored is not included in EnerNOC's reported performance, and
therefore EnerNOC's load reductions may differ from those RMP reports. ln 2013, the average
performance factor was84o/o, which indicates the percentage of customer load opting out of events.
EnerNOC's implementation of this ILC program was consistent with its approved agreement with RMP.
Review af 2OL3 enrollment and enablement
Customer outreach
After regulatory approval was obtained, EnerNOC initiated outreach to eligible irrigators. EnerNOC
worked with RMP to introduce the program changes and rules via marketing collateral, including RMP's
website, an FAQ, and postcard mailings. EnerNOC led "town hallstyle meetings" in ldaho Falls, Preston
and Rexburg, ldaho. A dedicated team at EnerNOC called and met with potential participants. EnerNOC
also formed a channel partnership with Spartan Energy Control Systems, who knows irrigators through
normal course of business and from installing equipment during previous load control program years.
EnerNOC's 2013 enrollment efforts focused on transitioning participants from prior years, especially
given the short time between regulatory approval and the program season. EnerNOC aimed to identify
load that was best fit for the new program structure and would provide the greatest financial incentive
to the participant. Pumps with load during program hours and weeks, as well as larger pumps, were
targeted in conversations.
New participants and pumps of all sizes were eligible and welcome to participate. However, smaller
pumps and pivots do not typically use enough electricity during peak periods to cover the costs of
participation in the program, and thus were not prioritized for enrollment.
Provider payment structure
EnerNOC and Rocky Mountain Power established three tiers for payments in order to provide fair and
consistent treatment for sites of similar size and operation. The tiers rewarded customers who made
larger contributions to the program. A customer's entire portfolio of eligible sites was evaluated in
aggregate to determine the average expected kW per pump and subsequent payment tier as described
in Figure 1.
Over 100 kW 23 25 N/A
50-100 kw 19 2L N/A
Under 50 kW 19 2L s1s00
Confidentiol dnd Proprietary Page 4
Rocky Mountain Power
Exhibit No. 1 Page 433 of 495
Case No. PAC-E-1+07
OTNERNoc PON'ER
ADffi&Sl$rffir
The bonus incentive rate was designed to encourage customer sign-up by rewarding all participants if
the entire enrolled portfolio size was greater than 125MW. The 2013 enrolled portfolio achieved this
goal, so all participants received the bonus rate.
ln order to cover the costs of participation in the program, an enablement fee was necessary when the
average expected load per pump was less than 50 kW. Most customers with primarily small pumps
chose not to enroll in the program in 2013 due to the enablement fee. Customers with a variety of
pumps most often chose to enroll only their larger pumps to take advantage of the higher base incentive
rates and to avoid the enablement fee. No customers chose to pay the enablement fee in 2013.
Enrolled customers
Between March 15,2013 and July LO,2OL3, EnerNOC enrolled 320 RMP accounts at 1,354 sites. Figure
2 shows the split of enrolled accounts and sites across the two regions. Billing kW is the 2013 RMP peak
demand.
Figure 2 is a snapshot in time as of July, L0,2073. Not all customers were able to be enrolled or enabled
prior to the end of the 2013 ILC season due to timing considerations or technical challenges. Customers
who enrolled prior to the end of the season but did not have the opportunity to fully participate in the
program received transition year payments from RMP and EnerNOC.
Figure 2: Enrolled and participating RMP accounts and sites compared to Schedule 10 Customers, as of
,10,2013
Count of Billing
Account/ kW
Site
Count of
Account/
Site
Billing
KW
Count of Billing
Account/ kW
Site
Schedule 10
Customerc
L,756/ 458,258
4,863
'J,,6921 L36,O73
2,743
3,4/,81 594,331
7,605
Enrolled 2581 220,793
t,tL4
621 26,679
240
247,47232Ol
1,354
Participating 232/ t96,946
977
s4l
207
24,tLg 2861 22t,O64
t,L78
EnerNOC site servers
By July L0,2013,286 RMP accounts and 1,178 RMP sites were participating in the ILC program. The
majority of these sites participated using an EnerNOC site server (ESS). The ESS solution includes
hardware/software for remote load control and energy monitoring at the pump panel. EnerNOC Field
Operations deployed 1,323 ESS devices across 1,075 sites by midJuly. This represented the bulk of
installation activity for 2013.
Due to volume of work orders and timing of enrollment, some sites were not able to be installed with an
ESS prior to the program start. lnstallation efforts were also delayed by the following factors:
o Winter and spring weather impacted access to certain geographic regions.
\Mtness: Kathryn C. Hymas
ROCKY MOUNTAIN
Confide ntial and Proprietary Page 5
Roclq Mountain Power
Exhibit No. 1 Page 434 of495
Case No. PAC-E-1+07
OTNERNoc
Vvitness: Kathryn C. Hymas
ROCKY MOUNTAIN
POvt,ERr DMSS Of PSflCfrF
o Customer availability limited access of electrical subcontractors to sites.
o Needed irrigation system repairs postponed installation.
r Pumps and irrigation systems needed to be operating under load in order to confirm the
functionality of the devices. Delayed start-ups delayed the ability to verify functionality.
Legacy devices
A sub-set of participating sites in 2013 used data from legacy irrigation load control devices already in
the field from previous years. These legacy devices report changes in pumps' onloff status rather than
reporting the energy usage. The allowance of these devices was critical in enabling customers to
participate in the 2013 program despite the aggressive program launch schedule. Moving forward in
2014, EnerNOC has been installing ESS devices at these sites so that their curtailment can be more
accurately monitored. No legacy devices will be involved in a customer's participation in 2014.
Technical challenges
Some customer sites were not able to be installed in 2013 due to technical challenges as described
below.
1. Sites with 2300V services were not able to participate in the 2013 season.
lssue
o These sites primarily use old submersible pumps, which are often large horsepower (on the
order of 800hp) and are costly to replace. Customers expect to replace these pumps over time,
only as necessary.
o Safety concerns prevented the installation of current transformers at sites with 2300V service.
Solution
o To enable this load for ILC participation in 2OL4 (before the customers have replaced these
pumps), EnerNOC has requested the installation of utility KYZ pulses as an alternative energy
data source.
o Rocky Mountain Power agreed to replace existing meters with those compatible with KYZ pulse
outputs.
o EnerNOC will install an ESS system at these sites utilizing the K\rZ pulse meters. Customers will
participate manually, but all load will be monitored to verify performance.
2. Sites without cellular reception could not pafticipate in 2013.
lssue
o Data communication is necessary for EnerNOC devices to enable control of pumps for event
participation and to report energy usage for payment calculations per program rules.
Solution
o EnerNOC continues to explore alternative solutions for future participation; however there is no
solution for 20L4.
Confide nf i a I a nd P ra prietary Qnnc A
OTNERNoc
Rocky Mountain Power' Exhibit No. 1 Page 435 of495
Case No. PAC-E-1+o7
\Mtness: Kathryn C. HymasV,ROCKY MOUNTAINYporen\^qvsmwwpw
Data quality challenges
EnerNOC's device solution for ILC includes use of current transformers (CTs) to monitor the pump's
curtailable load in 5-minute intervals. The specific configuration of installations was virtually identical
across all sites and was designed for minimum points of error. ESS monitoring was at the pump panel
level, so demand data did not necessarily correspond one-to-one with utility meter load. This added a
layer of complexity to data quality verifications.
During the course of verification, EnerNOC identified several data quality issues and worked with RMP to
determine the appropriate resolution and payment method for customers as needed. The key technical
issues identified were as follows:
1. Sixty-one sites were identified as having a magnitude offset in tlre 5-minute interval data.
Root Cause
o Errors in the CT phasing or system programming caused the offset.
Solution
o These issues have been fixed through the course of on-site maintenance visits.
o EnerNOC expects to be able to accurately reprocess readings in 2014 once irrigation load
resumes.
o To calculate 2013 performance, EnerNOC and RMP agreed to adjust actual electric demand.
2. Twenty-six sites had a persistent data quality issue during program hours and demonstrable
participation in ILC events.
Root cause
o lncorrectly installed CTs on variable frequency drive irrigation systems resulted in erroneous
readings when the pump was not running at either peak usage or not running at all.
Solution
o These installation issues have either been fixed on-site or work orders have been created for
the spring of 2074.
o To calculate 2013 performance, EnerNOC and RMP agreed to adjust actual electric demand.
3. Sixty-seven sites reported no data during events, but the customers confirmed participation.
Root Couse
o Loss of power to EnerNOC's device on-site results in no data reported for those intervals.
o During events, lack of data is treated as zero load reduction; yet in these instances power
was cut to EnerNOC's device and a participating pump.
Solution
o EnerNOC and RMP agreed to adjust actual electric demand to zero kW for intervals during
the appropriate events upon verbal confirmation from the customer.
o For 2Ot4 pertormance calculations, EnerNOC is exploring the possibility of implementing a
remote "power off' signal to report when power is cut to the ESS.
Confi de nti a I o n d P roprietary PaEe 7
Rocky Mountain Power
Exhibit No. 1 Page 436 of 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
O=NERNoc V,;ROCKY MOUNTAINY(nowen
! a Drvrsfi or rcFicGr
Review af 2AL3 program performance
Impacts of pay-for-performance model
Due to the pay-for-performance program model, customers' success in and satisfaction with the ILC
program for 2013 varied according to pump run-time during program hours and participation across the
ten load control events called by RMP. The following four examples illustrate varying levels of availability
and participation at individual irrigation pumps in 2013. Screenshots are from EnerNOC's web-based
DemandSMART platform, where participants can view near real-time energy usage data. ln each figure
the x-axis shows time and the y-axis is actual electric demand kW, as measured by EnerNOC's devices.
The shaded regions indicate weekends, which are outside of program hours. EnerNOC's equipment
solution provides 5-minute interval energy monitoring, in addition to remote irrigation equipment
control.
Figure 3: High availability and high participation
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Figure 3: High availability and high participation shows electric demand (kW) for a single pump across
the entire program season from June 10 through August 16. This pump participated in all events and
had high availability due to potato crops. This pump ran consistently for the entire ten weeks of the
program season and shut down (only) during load control events. For example on July 26, there was an
ILC event from 3 to 7pm Mountain Time, and load at this site dropped to 0kW. This pump had almost
100% availability and a tOO% participation factor for shutting the pump off during all ten load control
events. As a result, the customer received the maximum expected compensation for this pump.
Confide ntial * nri ?roprietary Page I
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Figure 4: Average availability and high participation shows electric demand (kW) across the entire
program season for a pump, which shut off for over three full weeks at the end of the program season.
As a result of this wheat harvest, the site's availability was about 65%. The pump did shut off during all
ten load control events, so the participation factor was 100%. The combination of high participation but
average availability resulted in the customer receiving average compensation for this pump. Payment
could have been higher with longer run-time.
Figure 5: Low availability during program hours
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Exhibit No. 1 Page 437 of 495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
Ditn lnteryal Vrs
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Figure 4: Average availability and high participation
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Figure 5: Low availability during program hours focuses on a two-week period during the program
season in order to illustrate this pump's time of use. Note on July 2nd, the pump cycled usage regularly
but was watering most often during early morning hours (e.g. 3 am), which are not covered by the
program hours (12 to 8 pm). The pump ran most consistently on weekends (note the light blue
columns), which are not included in program hours. As a result of alfalfa crops and running at night and
on weekends, this pump had low availability during the program hours. This site participated in all
events; however low availability resulted in a much lower overall payment.
Co nfi de nti al a n d P ro pri etary Page 9
Roclq Mountain Power
Exhibit No. 1 Page 438 of 495
Case No- PAC-E-1+07
Wtness: Kathryn C. HymasvtRocKY MOUNTAIN
YPOWen! ^owmff?8fcmP
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Figure 5: Low participation during events
m,
Is
5A
nange
orl2l,/xrl - a7l27l:Nt, ra f ,_ ?m 6 ru 1r
Figure 5: low participation during events shows a single week of the program season in order to
demonstrate pump run-time during a week with multiple load control events (week of June 22 to 27).
This site has high availability but fell behind on watering and needed to opt out of the events on July 25
and 25. Lack of participation is apparent because the pump ran without shut-offfrom Monday, June22
until the following weekend. As a result, the participation factor for this pump was lowered by 20% (two
events out of ten total events in 2013) across the entire program season. Payment for this pump was
lower due to the opt-outs during events, and could be raised with higher participation during events.
lmpact of crop type
Crop type typically correlates with availability and can be a predictor of customer success in the ILC
program. lrrigators in ldaho and Utah most commonly grow alfalfa, wheat, barley, potatoes, corn, or
some combination thereof over the course of a multi-year planting schedule.
Alfalfa is typically grown on a five to seven year planting cycle and is watered consistently across
the season. Alfalfa can be grown across the ldaho and Utah territory. Prices are particularly high
right now; so many irrigators are choosing to plant this crop. Typically alfalfa crops have the
flexibility to participate in events due to a tolerance for shifts in watering schedules. However,
the load profile of alfalfa is intermittent. Pumps watering alfalfa are shut off for two periods
each summer for harvest. These harvest periods can last a week or more, resulting in
significantly reduced availability.
Wheat and barley will typically require large amounts of water early in the program season, and
then pumps will be shut off once for several weeks to allow the crop to dry out for harvesting.
These are tolerant crops that can withstand a couple off-schedule days to participate in load
control events. However payments will be affected by availability.
Potatoes are a water-intensive crop that is often rotated with wheat after a few years of
harvest. Potatoes are significantly more sensitive to irrigation schedule interruptions than wheat
or alfalfa. ILC participants with potato crops will have high availability but likely a reduced
flexibility to participate in load control events. Potatoes will also be particularly sensitive in
drought years, further impacting event participation.
Corn and fields watered for !ivestock pasture have less consistent or predictable irrigation
schedules, and are mostly found in Utah or on dairy farms.
Jul 25, 2Ol :} 4So Fi,t
EL(tri*y D"ilrnd kyr) 5o.2o kw
AaBkwdUe
,1Hou
Confidentia! and Proprietary Paae 10
Rocky Mountain Power
Exhibit No. 1 Page 439 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
OrruHRNoc VROCKY MOUNTAINYporyen\ o o,vcmor rcrrmn
Crop rotations further impact pump availability year-over-year. Over the course of the ten-year program
period, most irrigators fall into one of the following four crop schedules:o tOO% alfalfa;o 50% wheat/50% potatoes;
o free rotation between alfalfa, wheat, and potatoes; or
c LOO% corn or pasture field irrigation.
A pump that waters wheat in year one with high event participation and 50% availability due to
harvesting downtimes may water potatoes in year two. This crop shift would likely result in a shift to
lower participation but 95% availability, making it difficult to use single year performance as a predictor
for program fit across the ten-year period.
lmpact of irrigation technology and water availability
While pump size is a clear determinant of total availability in the ILC program, irrigation technology and
water availability also impact irrigation pump run-time and thus can affect customer success in the ILC
program. Pivot irrigation systems are operationally easier to manage for load control events than a
wheel line or hand line irrigation system, and thus are favored for participation in the program. lt is
important to note that a potential customer will never be disqualified solely based on crop type or
irrigation technology. Enrollment will be judged based on customer's willingness to participate.
The majority of large - several hundred horsepower in size - irrigation pumps enrolled in the program
are attached to a deep well and found in regions with low surface water availability. Growers with deep
well pumps have a high level of control over their irrigation schedules and may have greater flexibility to
participate in load control events, but may be more constrained by water resources.
Surface water pumps are generally found in areas with reliable water availability: ldaho Falls, south
ldaho and select areas of Utah. These pumps are generally up to 100 horsepower in size and are used to
move water laterally on demand from canals. Surface water pumps generally operate on a schedule
arranged in advance with the canal company, which can lessen schedule flexibility to participate in load
control events. Lack of coordination can result in flooding. Those growers using surface water pumps
who participate in ILC often have large operations with many pumps that can manage the operational
risk of a load control event.
Geographic segmentation
Based on conversations with irrigators in 2013, EnerNOC's marketing and sales team has characterized
the ldaho and Utah customer territory into regions based on geography and observations of crop type
a nd operational patterns.
ln ldaho, participation, as measured by load contribution, was predominantly in four regions in 2013:
Mud Lake (Hamer, Mud Lake, Terreton, Monteview, and Dubois), ldaho Falls (ldaho Falls, Firth, and
Shelley), South Fork Snake River (Roberts, Rigby, Menan, Ririe) and Rexburg (Teton, Sugar City,
Clementsville, Rexburg, Newdale). These areas generally have larger, deeper well pumps that are natural
fits for the ILC program. Penetration, as compared to an estimate of the existing non-enrolled potential
load in the region, was also high in these four regions, particularly in South Fork Snake River.
Participation, as measured by load contribution, was highest in three regions in the Utah service
territory: Cedar City Parowan, Paragonah, and Cedar City), South Utah (Enterprise and Beryl Junction),
and Delta (Leamington, Delta, Holden, Lynndyl, and Mccornick). ln general Utah load is made up of
Confid e nti o i a nd P ro pri eta ry Page 11
Roclq Mountain Power
Exhibit No. 1 Page 440 of495
Case No. PAC-E-14-07
OrruERNoc
^}^n
.o"e' non"'
."o9
"S'
Vvitness: Kathryn C. Hymas
ROCKY MOUNTAIN
POIft'ER
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smaller horsepower pumps than in ldaho and systems are older, making the mechanics of ILC
participation more difficult.
Weekly available load reduction
The RMP ILC program is evaluated based upon average available load reduction (kW) during program
hours from L2 to 8pm MT, non-holidays. ln 2013, the portfolio average available load reduction was
120.86 MW with a contribution of 107.1 MW in ldaho and 13.76 MW in Utah.
Available load reduction for the total portfolio varies week over week due to irrigation use as displayed
in Figure 7 below. Enrollment and registration of sites contributed to some of the ramp observed in the
first three weeks of the program period. The other contributing factor was ramp in operation of
irrigation systems for watering. The drastic reduction in available capacity from July 22 through August 4
was driven by the shut-off of pumps for harvest of crops, including grain and alfalfa.
Figure 7: Weekly averate available load reduction
..+-Total Portfolio ..o-ldaho *.,6*utah
180
160
L40
120
100
80
60
40
20
==g,lts(!
^na'o' ^r"-- ^fns ^eu-f ^€"d9
,--. .gns
Program Week, beginning
lrrigation patterns in ldaho drove total portfolio availability due to the disproportionate amount of
eligible and participating load in ldaho. During the week of July 29, ldaho available load droppedto52%
of the L45.39 MW peak available load during the week of July 8. Pumping in ldaho resumed for the last
two weeks of the program season (August 5 through August 16) but did not return to peak levels.
Available load in Utah also varied week over week but was slightly more consistent than in ldaho.
During the week of July 22, available load droppedto 62% of the program peak in Utah. ln contrast to
ldaho, the last program week had the highest available load over the summer in Utah - 18.67 MW.
Canfidentiol ond Proprietary Page i.2
Roclry Mountain Power
Exhibil No. 1 Page 441 of 495
Case No. PAC-E-1+07
O=xrERNoc
Vurtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POI,I'ER
ADrc*Of ffirffiP
The concept of availability and pay-for-performance is new to customers participating in lLC. EnerNOC is
taking the opportunity during discussions about payments, the enrollment process, and periodic check-
ins with customers to explain and answer questions about this concept. Some customers ran entirely off
peak, especially those on Utah's time of use rate, which resulted in significant differences between prior
years' ILC incentives and expectations set during the 2013 enrollment process.
Load control events
ln 2013, there were ten mandatory program events across ldaho and Utah. Actual load reduction was
measured as the difference between actual demand during the event and baseline demand. Baseline
demand was the average demand during program hours (12 to 8pm MT) on the most recent non-event,
program day. Actual Load Reduction (kW), Baseline Demand (kW)and Load Reduction Performance
Factor as reported here correspond to 5-minute interval energy usage measurements from EnerNOC's
equipment at customers' sites. These measurements may not correspond to realized load reduction on
RMP's system. Load reduced but not yet monitored is not included in EnerNOC's reported performance.
This includes sites that were enrolled but not enabled with a monitoring solution, for which RMP
provided a transition year payment.
The 2013 portfolio delivered 115.5 MW on average. Performance factor, the measure of actual load
reduction compared to baseline demand, was 84% on average for the portfolio. Performance factor is
designed to measure customers' choices to opt out, or to not participate in events, and is used to adjust
availability payments because of the pay-for-performance nature of the program. Performance factor
should not be confused with any notion of performance against a capacity nomination. Peak delivery of
135 MW occurred during the July 10 event. The portfolio also had maximum potential for curtailment on
July 10 with a baseline demand of 156.5 MW.
Figure 8 summarizes portfolio load reduction compared to baseline. Figure 9 details the actual load
reduction, baseline demand, and performance factorfor each state and event. Maximum event
participation was achieved during the first dispatch on Jungiy 18 with a performance factor of 93%.
While Utah load only contributed to about LL% of average baseline load, Utah participants performed at
87% on average, compared to 84% in ldaho.
Figure 10 below provides a detailed list of the ten mandatory events, as well as one program test event
and five canceled events. Several unexpected scenarios occurred during the 2013 event season:
Canceled dispatches on the day-of (after day-ahead notification to EnerNOC and participants)
were not expected. EnerNOC was able to notify customers of cancelation; however these
instances caused confusion and complaints. EnerNOC and RMP are working to limit future
cancelations to emergency scenarios only.
Utility power outage outside of events and/or program hours affected customer's ability to
participate. RMP agreed to compensate irrigators for participation in these instances as a show
of good faith. EnerNOC incorporated this scenario into opt out processes in order to properly
track these instances.
Co nfide ntia I a nd P ro prieta ry Page 13
OrruERNoc
A utility power outage during an event caused data gaps on EnerNOC's load control devices, and
some pumps resumed normal operations during the event when power was restored. This
resulted in a load increase aross the portfolio during the last hour of the event on June 28.
EnerNOC is working to identify a better solution to track this type of exception in the future;
however all systems functioned as designed and expected.
PacifiCorp requested to exclude a sub-set of customers from already dispatched events due to
changes in system needs or vulnerabilities. EnerNOC was able to respond to such a request on
July 1 by restructuring records and notifoing customers. EnerNOC and RMP are working on zonal
dispatch in order to better accommodate such needs in the future.
PacifiCorp requested staggered dispatches after the July 10 event in order to minimize voltage
spikes on RMP's system. EnerNOC implemented staggered dispatches by randomly grouping
participating sites into ten groups with delays of one minute between remote curtailment of
each group. This lead to a slower reduction in load over the course of ten to fifteen minutes
(due to natural system delays).
Figure 8: Load reduction for total portfolio across ldaho and Utah, by event
I Load Reduction (MW) Ii Baseline Demand (MW)
150
100
=8060
40
Rocky Mountain Power
Exhibit No. 1 Page 442 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
V-ROCKY MOUNTAIN\TPOAIER
\emmmm
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20
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Confidential and Proprietory Page 14
Rocky Mountain Power
Exhibit No. 1 Page 443 of 495
Case No. PAC-E-1+07
Wrtness: Kathryn C. Hymas
OrrurRNoc VROCKY MOUNTAIN\f pouvER
\eorcmwm,mr
ldaho
Utah
LO6,743,
100,335
6,407
114,556
LO7,42L
ldaho
Utah
L29,758
LL6,987
!2,77t
L47,734
L32,280
15,455
88%
88%
83%
ldaho
Utah
t,,,',L28
97,850
!3,277
129,605
113,845
L5,76L
86%
86%
w,
109,395
13,509
15t,24
L34,864
16,380
8t%
8Lo/o
w"
ldaho
Utah
L25,160
110,009
152,853
136,109
82%
8L%
15,151
ldaho
Utah
115,104
L02,483
12,622
155,498
14t,293
15,205
74%
73%
w"
ldaho
Utah
135,328
120,806
L4,522
ldaho
Utah
106,339
t0,45L
134,505
122,837
!1,674
87%
87%
W,
ldaho
Utah
95,531
85,6M
ldaho
Utah
96,667
86,765
9,902
tl,z,630
100,949
11,681
86%
86%
ffi"
ldaho
Utah
LLs,62L
103,661
1r"960
L36,972
L23,269
13r?03
84%
84%
8?%
*Actual Load Reduction (kW), Baseline Demand (kW) and Load Reduction Performance Factor as reported here
correspond to S-minute interval energy usage measurements from EnerNOC's equipment at customers' sites.
These measurements may not correspond to realized load reduction on RMP's system.
Confidential and Proprietary Poge 15
Rocky Mountain Power
Exhibit No. 1 Page 444 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
OrruERNoc V,ROCKY MOUNTAINx(POUTER
!4DffifttrffiffiP
of10: List of 2013 event
Program
Test
- Pre-season portfolio test to verify EnerNOC
hardware/software and customer notifi cations.
Mandatory 5lL8l2OL3
3:fi)pm
- EnerNOC system issue prevented -6 MW of load on -40
devices from receiving the curtailment signal. EnerNOC
curtailed these pumps over the first hour of the event.
Customers' payments were not affected.
5127l2gt3
3:00pm
6127120L3 - RMP canceled the event due to transmission returning
1:50pm to service and wind/other generation levels different than
Mandatory 5l28l20t3
3:fi)pm
6/28/20L3
7:00pm
- RMP power outage at -5:45pm. Some sites' power
restored prior to event end time and pumps with auto-
Mandatory 7ltl20L3 7lLl20L3 RMP requested removal of participants on temporary3:00pm 7:00pm transformer from event.
- EnerNOC and RMP worked with participants affected by
Mandatory 7l2l2lt3 71212013 Participants cited high temperatures and third3:00pm 7:00pm consecutive program day of dispatches as primary opt out
reasons.
- EnerNOC and RMP worked with participants affected by
on 6/28 to compensate appropriately.
Mandatory 71312013 713120L3 Participants cited high temperatures and fourth
3:00pm 7:00pm consecutive program day of dispatches as primary opt out
reasons.
- EnerNOC and RMP worked with participants affected by
power outage on 6/28 to compensate appropriately.
Mandatory 719120L3 719/20L3 - Localized power outage observed prior to event.
- High frequency of opt outs for potato
Mandatory 7lt0l2013 7lL0l20L3 Localized power outage observed prior to event.
Canceled 711.L12OL3 - 7/tL12073 - RMP canceled due to change in system needs.
3:00pm 10:00am
Canceled 7lt6l201,3 - 7/16/2013 - RMP canceled due to change in system needs.
Canceled 7h7l20t3 - 7lt7l20L3 - RMP canceled due to change in system needs.
3:(X)pm 10:55am
Mandatory 7lt.glz0l}
3:fi)pm
7/L8/2OL3
7:00pm
- lmplemented staggered curtailment. lt took 15 minutes
into the event window (3:15 pm) for all devices to receive
Canceled 7l22l2OL3 - 7/22/2OL3 - RMP canceled event due to major load tap changer
3:00pm 11:00am malfunction. Dispatch could have caused serious voltage
issues for customers.
Mandatory 7l25l2OL3 7/L8/20L3 Potato crops continue to opt out with high frequency.
- Almost 35% of oortfolio load is down for harvest.
Mandatory 7l26l2vlg 7/L8/20t3 Potato crops continue to opt out with high frequency.
- Almost 35% of Dortfolio load is down for harvest.
Confidential and Proprietary Paae 16
Rocky Mountain Power
Exhibit No. 1 Page 445 of 495
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
OrruERNoc UROCKY MOUNTAINYpowrn\"ummortwmr
Customer satisfaction and issues
EnerNOC sent an end-of-season survey to gauge customer satisfaction via email on October 16, 2013.
The survey consisted of fifteen questions and comment fields. A small sub-set of customers responded:
twenty-two in ldaho and six in Utah. Eight quantitative questions were asked:
r Overall satisfaction with EnerNOC
o Likely to recommend EnerNOC
o Enrollment and contracting process
o lnstallation process of EnerNOC equipment
o Maintenance of EnerNOC equipment
o Ability to play your irrigation schedule and participate in ILC dispatches
o EnerNOC customer service
o Opt out process
Across these quantitative questions, average customer response was a 7 on a scale of 1-10 where 1
means "very dissatisfied" and 10 means "very satisfied". Responses and comments indicated the
following areas of customer concern:
o Loss of value compared to previous program rules, functionality and/or compensation.
o Delayed device enablement and/or rushed program start.o Ongoing hardware issues with EnerNOC devices.
o Event cancellations were challenging for customers due to needs to plan irrigation schedule.o EnerNOC's call center needs to improve awareness about irrigation and agriculture,
EnerNOC is using customer feedback regarding the enrollment and enablement processes and event
experience from 2013 to set expectations and shape improvements for future program years.
Ca nfide nti a I a nd P ro prietary Poge L7
Roclry Mountain Pow€r
Exhibit No. 1 Page 446 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
OrnrrRNoc IT,,RACKY MOUNTAIN
YflPOVrten! a Divsfr o. PffiriffiF
Key lessons }earned from 2013
EnerNOC and Rocky Mountain Power identified the following lesson learned for 2013 to apply to 2Ot4
and future years.
Enrollment and retention
1. Enrollment Timing
Summory
o Despite EnerNOC's concerted efforts to quickly finalize as many customer contracts and
installations in the short time period between regulatory approval and the program season, it
was not possible to enroll and enable all participating sites in time for the 2013 season.
Customer Feedback
r Customers generally assumed that if installation had not yet been fully completed at their sites,
they could participate in the program manually without monitoring or remote control.
o ln order to address those customers that were enrolled but not enabled with a monitoring
solution, RMP decided to provide a transition year payment.
Approach for 2074
r EnerNOC will continue to enroll customers for 2014 and manage the timing of this enrollment
and enablement closely. lnstallations and maintenance from 2013 enrollments continued post-
season through November 2013, and re-started in March 2014.
o EnerNOC is communicating to new customers that sign-ups completed after April 18 are unlikely
to be enabled in time for program start on June 9.o EnerNOC is actively communicating with all customers about the status of their enrollment in
order to ensure proper expectations.
2. Pay for Perfonnance
Summory
o ln 2013, the ILC program changed to a "pay for performance" compensation model where
participants are compensated based on average availability during the program period. This
compensation model differs from the previous ILC program model in which customers were
generally compensated based on pump size and real-time metering was not a requirement.
Customer Feedbock
o EnerNOC is working with customers to ensure that they understand how the calculations were
completed in 2013 and to identify any potential errors.
. Many customers' perception is that their aggregate availability for the 2013 season was lower
than expected.
Approoch for 2074o EnerNOC will continue to educate participants on the program model during new sales outreach
and pre-season conversations with current customers.
r EnerNOC and Rocky Mountain Power are examining different approaches to calculating site
availability for future program years, but do not intend to make a change for 20L4 based on a
single year of historic program data.
3. Site Size
Summaryo ln previous years, ILC participants could enroll and receive compensation for smaller pumps.
Because of the economics associated with installing new technology at each participating site,
Canfide ntial a nd Praprietary Page X"8
Rocky Mountain Power
Exhibit No. 1 Page 447 ol 495
Case No. PAC-E-14-07
Vvitness: Kathryn C. Hymas
OrxERNoc V,ROCKY MOUNTAINxlnowER
!^offifttr'MrmP
EnerNOC implemented an enablement fee for customers whose average expected load was less
than 50 kW in order to help pay for installation costs.
Customer Feedbock
o Customer feedback regarding pump size has been similar to discussions and reactions to the pay
for performance compensation model. When customers previously received compensation for a
number of smaller pumps, their overall compensation may have gone down in 2014 if those
pumps were not be enrolled under the new program model.
Approach for 20L4o EnerNOC and Rocky Mountain Power continue to explore ways to maximize cost-effectiveness
for small sites in the program . For 2074 account managers will continue to focus discussions
with potential participants on factors that impact availability, specifically crop type, irrigation
schedule, irrigation hardware, and harvesting schedule.o Expected capacity pricing tiers will not change.
Enablement
l. Device Installation Challenges
Summary
o Errors were made during early 2013 installations related to contractor training on the new
hardware.
Customer Feedbackr Some customers expressed frustration with delays to program enrollment and by the multiple
contractor visits required to resolve hardware issues.
Approoch for 2074o EnerNOC has addressed these process errors and fixed the installs in question.
o Where appropriate, customers received a transition year payment to compensate for the
missing period of program participation caused by the issue.
2. Maintenance Calls to Customers
Summaryo ln order to verify metering connectivity and device functionality, EnerNOC sometimes called
customers to ask about pumping schedules and inquire about status of EnerNOC's devices
during the 2013 program season.
Customer Feedbock
o Particularly for some customers with many sites participating in the program, these calls
became overly burdensome.
o Some customers complained that EnerNOC staff was not always familiar with site and pump
configurations or lacked an understanding of the customer's pumping operation.
Approoch for 2074o EnerNOC is re-visiting processes in order to reduce the number of maintenance calls placed to
customers.o EnerNOC is exploring the possibility of implementing a remote "power off' signal to report
when power is cut to the ESS. This will provide additional information about the root cause of
issues.
r EnerNOC is conducting training for customer-facing teams about irrigation operations in order
to improve the quality of interactions with ILC participants.
Co nfide nti a I a n d P roprieta ry Page L9
Roclq Mountain Power
Exhibit No. 1 Page 448 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
0rNERNoc v/,RocKY MOUNTATN\5pCIAlER
\ r o,vsmoo mormr
3. Pivots Running Dry
Summary
o Remote controls on EnerNOC metering devices are designed to shut off and restart water
pumps, but are not always able to also shut down or restart connected pivot irrigation systems,
depending on the configuration. When pumps are shut down but pivots continue to run, these
pivots are said to "walk dry", moving across fields without watering crops.
o Such an occurrence is an operational inconvenience for farm managers, who must manually
reset pivots to the start position at the time of pump shut off.
Customer Feedbock
o Some customers asked whether EnerNOC's ILC equipment could provide functionality to include
pivot shutdown and restart.
Approoch for 2074o EnerNOC is investigating technical solutions. Such requests are being addressed on a case-by-
case basis in order to determine the scope and cost of each individual project to determine
suitability for the RMP program.
4. Load not being captured on enrolled meters.
Summory
o EnerNOC is monitoring load at the pump panel, and therefore does not always capture smaller
pump or pivot load attached to the same utility meter but not directly connected to the primary
pump.
o ln some cases, these loads were curtailed during 2013 events but not included in availability for
compensation due to lack of metering data.
Customer Feedbocko Customers who experienced these unmeasured load reductions would prefer to receive
compensation for all devices that shut down during events, whether measured and metered or
not.
Approach for 20L4o EnerNOC is adjusting training for new installations in 2074 in order to capture as much of this
additional load as possible. Contractors will place CTs prior to the starter on all new installs and
at existing sites when they are visiting the area for maintenance.o EnerNOC is also currently field testing other CT models which will provide additional flexibility to
enroll sites where previously there were physical limitations to CT size.
Dispatch management
1.. Event Frequency
Summary
o ln 2013, Rocky Mountain Power exercised ten of twenty available events (50%)and forty of
fifty-two available event hours (77%1, which amounted to event dispatch during 10% of all
program hours.
Customer Feedback
o Feedback from ILC participants suggests a perception that this utilization rate is high even
though there is an understanding of the program rules and variability year over year.
Approoch for 20L4
o EnerNOC has communicated custome/s concerns to RMP.o RMP plans to train the PacifiCorp Front Desk staff about the impacts of events on irrigators.
Confide nticl c nd Praprietary Page 20
OTNERNoc
Rocky Mountain Power
Exhibit No. 1 Page 449 of 495
Case No. PAC-E-1+07
\Mtness: Kathryn C. Hymas
aF.)ROCKY MOUNTATN\TPOWER
\ onwmormrme
2. Back-to-Back Event Pattern
Summary
'a--o When multiple events were called in a program week, the event days were always back-to-back.
ln addition, there was a string of consecutive events days from Friday, June 28 through
Wednesday, July 3.
Customer Feedbock
o A back-to-back event pattern is particularly difficult for irrigation DR participants. After two days
of deferred irrigation, it becomes more difficult to catch up on watering and achieve the same
crop yields.
Approach for 2074o EnerNOC has brought this feedback to RMP to help ensure that PacifiCorp's Front Desk
understands the impact of back-to-back dispatches on irrigators.
3. Day-Of Event Cancellations
5ummoryo Event cancellations were a primary source of concern for participants in 20L3. There were five
events cancelled, each within five hours of the scheduled event start time.
Customer Feedbocke Cancellations are most challenging for irrigators who make decisions early in the morning about
their operations and staff resources. Additionally, due to a business modelthat compensates
participants for availability, if irrigators who had already planned to be shut down for the event
day did not resume normal operations upon receiving the cancellation notification, their
availability and payments were negatively impacted.
o This problem also impacts the day-ahead baseline when an event is called for the day following
a cancellation.o Several participants have communicated that they would like cancellations to count towards
event maximum limitations. lf this were the case in 2013, the program would have been called
in excess of the prescribed fifty-two event dispatch hours.
Approoch for 2074o RMP recognized that day-of cancellations or reserving the program day-ahead is not the
intended use of the program.
o RMP is working to avoid event cancelations unless in the case of a true system emergency.
4. Event Notifications
Summory
o As part of EnerNOC's standard process, participants received day-ahead notifications of event
start and end time, a reminder notification approximately four hours prior to event start, and
event end notifications from EnerNOC. Notifications were delivered via phone call, email, and
SMS.o ln cases of back-to-back event days and/or cancellations, the volume and cadence of
notifications in 2013 was higher than expected for some customers.
Customer Feedbock
o While EnerNOC received a feedback from participants about the utility and timing of event
notifications via phone, email and SMS, much of it was conflicting. For example, some providers
did not want to receive the restore/event end notifications, while others appreciated these
messages.
Ca niide ntia I a n d P ro prietory Page 21
Rocky Mountain Power
Exhibit No. 1 Page 450 of 495
Case No. PAC-E-1+07
OrruERNoc PO\,\'ERADI%*OFffilSP
Approoch for 2014
o EnerNOC is working to improve its notification system in order to provide greater flexibility in
2014. EnerNOC expects to be able to provide more explicit communication about which pumps
are involved in a dispatch via email and to condense multiple notices into one message delivery.
5. OptOut and Control ofPumps
Summoryr ln 2013, customers were required to call EnerNOC's support center to opt out of events.
o ln previous years, customers could use the legacy system to log in remotely and opt out.
Customer Feedbock
o Overall, feedback suggested that the 2013 opt out process worked well for customers and the
event management team.
o After the first two events, EnerNOC organized the process around RMP's Site lD which helped to
ensure effective and accurate communication with customers.
o A handful of current and potential participants requested that this functionality be provided in
EnerNOC's portal for future program years.
Approoch for 20L4
o EnerNOC is not able to provide web-service opt out functionality for 2014 but will continue to
explore the needs and development of this functionality for future years.
6. Pre-Season Portfolio Test
Summory
o A one-hour portfolio test was held prior to the mandatory program season start on June 4, 2013
for one hour (1:00 to 2:00 pm MDT). Only three sites opted out of the test, two of which were
under construction and the third because the primary contact was out of town.
Customer Feedback
o The pre-season portfolio test was a common pain point for 2013 ILC participants. Program
participants complained that the pre-season portfolio test was inconvenient and not worthwhile
as they did not receive direct compensation for participation in this test.
Approach for 20L4
r While a test was necessary in 2013 due to the new technology platform and business model,
EnerNOC and RMP do not intend to conduct a portfolio-wide test prior to the 2014 season start.
Equipment for existing customers will be tested on an as-needed basis to ensure pre-season
readiness.
o Newly-enabled sites will continue to undergo an acceptance test to verify equipment
functionality after installation.
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
Co nfic)e nti a I a n d P roprieta ry Page 22
Roclq Mountain Power
Exhibit No. 1 Page 451 of 495
Case No. PAGE-1rt-o7
Vutness: Kathryn C. Hymas
ROCKY MOUNTAIN
POUI|ER
A ONISION OF PACIRCORP
Appendix 6
Idaho Irrigation Post Peak Report
( P ropri e t ctt' an tl C o n"/idential I
ROCKY MOUNTAIN
POWER
E- h i bitt::Y Y."rTl?! :'"X'"J
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
2013 Idaho lrrigation Post Report
wRocKY MOUNTATN-<POWER
\ n orvtstoru oF PAcrFrcoRP
2013 Iduho lrrigation Post Peak Report
Executive Sponsor
Douglas N. Bennion, P.E.
Study Team
Director
Ken Shorff
Principal Authors
Tony Perkins
Mike Anderson
Contributors
Scott Murdock
Bill Comeau
November 2013
Field Engineering Page I of2l I1/201i
-ROCKY
MOUNTAIN-(PoturER
\ r o,vrsrcxr o+ uc,rrconp
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Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2013 lduho lrrigation Post Report
Table of Contents
EXECUTIVE SUMMARY
SYSTEM LOAD DATA ANALYSIS .....4
Idaho Irrigation Load ....................4
Idaho Transmission System ........10
IRRIGATION LOAD CONTROL PROGRAM DETAILS l1
Load Control Events in 2013 .......................11
System Concerns with Idaho Irrigation .......13
Harmonic Issues .......13
Load Control - Voltage Issues Due to Load Control Events. .................13
CONCLUSIONS .......L7
RECOMMENDATIONS........... ...........17
APPENDIX I.......... ............18
Harmonic Pollution Details....... ....................18
Crops Load Detail....20
Field Engineering Page 2 of2l t1/201i
ROCKY MOUNTAINffi
E,hibitlrTYY""sTHi:'"Xr";
Casa No. PAC-E-1+07
V\fitness: Kaihryn C. Hymas
2013 ldaho lrrigation Post Report
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Field Engineering Page 3 of21 I r/2013
v,RocKY MOUNTATN-ffPOWER
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Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2013 lduho Irrigation Post Report
EXECUTIVE SI'MMARY
Rocky Mountain Power conducts an Idaho post peak irrigation system review to understand the impacts
of Idaho irrigation load, and in particular the impact of the Idaho Irrigation Load Control Program. This
annual report communicates the findings, conclusions, and recommendations resulting from the review.
First, the 201 3 report analyzes system load data and irrigation load patterns during the 20 1 3 irrigation
season (June I through September l5). It discusses total Rocky Mountain Power Idaho load versus
Idaho irrigation load, and irrigation load control program participants' load versus non-participants'
load. In addition, it discusses how crop rotations and weather affect irrigation, and summarizes the
transmission system load in heavy use irrigation areas.
Second, the report analyzes the demand side management Irrigation Load Control Program and the
effects the program has on the transmission and distribution system. It discusses the details of the
dispatch events for 2013 and some of the system concerns with the program.
Finally, the report identifies conclusions and makes recommendations.
Some of the key informational points from the report are:
o The Rocky Mountain Power Idaho peak demand occurred on July 1,2013 when peak irrigation
usage occurred.
. Irrigation load in Idaho represents 37%o of the State total peak load.
. Idaho has 4863 irrigation sites with 19% of these sites participating in the Irrigation Load
Control Program.
o The Irrigation Load Control Program was dispatched ten times in 2013. The median estimated
curtailed load dispatch was 135 megawatts. The maximum dispatch event resulted in an
estimated curtailed load of 167 megawattsl.
. Based on work completed in2}ll and early 2012, the number of ANSI range A voltage
violations and the severity of the violations were reduced in 2013.
1 See Table 1, Maximum curtailment event occurred on7/O3/2O73
Field Engineering Page 4 of2l t 1/2013
ROCKY MOUNTAIN
trol,VER
.,,n,ont""lYI"iTl1[:,"Xr"J
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2013 ldaho Irrigation Post Report
SYSTEM LOAD DATA ANALYSIS
Idaho Irrigation Load
Irrigated agricultural land in southeastern Idaho served by Rocky Mountain Power is primarily in the
Snake River Plain. This area is an inverted triangle shape from Shelley on the south to Dubois on the
northwest and Ashton on the northeast; Arco on the west to furie (northeast of Idaho Falls) on the east.
Other areas in Idaho with inigated agricultural land served by Rocky Mountain Power are: Preston,
Malad, Marsh Valley, Montpelier, and in the Gem Valley around Grace, Bancroft and Chesterfield.
These other areas have much less irrigation load than the primary area in the Snake River Plain. See
Figure 1 for a view of the inigation loads. The green dots represent irrigation customers.
Irrigation water comes from either surface water-rivers, canals, ditches----or groundwater from wells.
Irrigation customers connected to the Rocky Mountain Power system use pumps driven by electric
motors to move water from the source, and pressurize it into an irrigation system. Electric pump motor
sizes reach up to 1000 horsepower.
Figure 1, Geographic Area
Field Engineering Page 5 of2l I t/201 3
ROCKY MOUNTAIN
POWER
E-hi bitl"":Y Y.iTfl ? :'"Xr"J
Case No. PAC-E-14-07
\y'Vitness: Kathryn C. Hymas
2013 ldaho Irrigation Post Report
Larger pump motors are used for drawing groundwater out of the deep wells in the area.
Irrigation systems can be a center pivot system' lFigure 2), a wheel line3 (Figure 3), or hand linesa
(Figure 4). A center pivot system will run continuously for the time it takes for a complete cycle. Wheel
lines and hand lines run 8 to 24 hours and then turned offto be moved manually.
Figure 3, Typical Wheel Line - Photograph
courtesv USDA NRCS
Figure 4, Typical Hand Line -
Photoeraoh courtesv USDA ERS
On July l,2Ol3 Rocky Mountain Power's Idaho load5 peaked at 814 megawatts at l0 pm MDT. Using
irrigation load control participant data as a proxy, it is estimated6 302 megawatts of Idaho irrigation load
and 512 megawatts of non-irrigation load occurred on July 1,2013. (Figure 5)
2 A pipe with sprinklers carried by wheeled towers in an arc around a center point.
3 A plpe with sprinklers attached on large wheels that is moved in a line across a field.a Pipes with sprinklers attached that are laid in a line on the ground.
I tdaho load was 14.8% of the Rocky Mountain Power total system load on July 1, 2013t Fol. pr.por", of this report irrigation load control participant data indicates a diversity factor of 65% which was used to estimate total system irriSation
impacts.
Figure 2, Typical Center Pivot
tdaho System Loading AllOLl2AL3*
I Non irigation Load I lrritation Load
Figure 5, ldaho System Loading
Field Engineering Page 6 of2l I 1/201 3
ROCKY MOUNTAIN
PWYER
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Case No. PAC-E-14-O7
\Mtness: lGthryn C. Hymas
2013 ldaho lrrigation Post Report
Rocky Mountain Power had 4,863 irrigation sites connected in the State of Idaho in 2013. The
undiversified demand for these 4,863 irrigation sites was 458 megawatts in July 2013. Of these 4,863
sites there were 941, or l9o/o, that participated in the company's Irrigation Load Control Program
(Figure 6).
ldaho lrrigation Sites 2013
a Totsl Number of lrrigation LGd Control Sites r Total non Load Control Irrigation Sits
Figure 6, ldaho lrrigation Sites
In July, the total undiversified demand of sites participating in the load control program was l9l
megawatts. On the day of the peak, 115 megawatts of load was curtailed by load control program
participant sites, another 42 megawaffs was available to curtail but needed to be excluded from the
dispatch due to system conditions, and 145 megawatts was utilized by non-participating irrigation sites.
This totaled an estimated302 megawatts of irrigation load in Idaho. See Figure 7.
ldaho lrrigation Site Load July 1, z0t3
I Total L@d of Non Load Control Sit6
xTotal LGd of Lcd Control Sites
a Load Cof,trcl not utilized by RMP due to rystem conditions
ligureT,ldaho lrrigation Customer Load July L,2OL3
Field Engineering PageT of21 11/24t3
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PO1TVER
'-n,ooX,TY
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Case No- PAC-E-I+07
\y'Vitness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
Idaho Weather
Southeastern Idaho weather in 2013 followed a similar pattem as 2012. The growing season
precipitation was less than 2009,2010, and 2011. Irrigation of Southeastern Idaho crops is necessary
because the weather during the summer growing season is typically warrn and dry. The amount of
spring precipitation in May and June, af[ects when irrigation begins. When there is less precipitation in
May and June, irrigation begins earlier.
June, July and August air temperature and precipitation affect the total summer irrigation electrical load.
Higher air temperatures and lower precipitation lead to higher summer irrigation load, since more
irrigation water will be needed on the crop. Data on precipitation, temperature, and irrigation powerT
demand for April tltough August of 2013 are shown in Figure 8.
Figure 8, April - August 2013: Weather and Power Use
SeeldahoTransmisslonSystem, pagel0,foradescriptionoftheeightsubstationsreferencedinFigureS
April- August 2013 Weather
-----.----.
0.60sm f--r :2013 Daily Precip., inches
-2013
Deilv Hish Temp, de8res F450
-2013,
8 SUB TOTAI- MVA
o
-- q
U, J( 'Eo
c
6
S :oo
E
lFi€o---,41vl
ESe<
=I 20o
0.40
0.20
0.00rlrllr,l,lr,llllll,r
Field Engineering Page 8 of2l 1t/2013
Rocky Mountain Power
Exhibit No. 1 Page 460 of 495
Case No. PAC-E-14-07
VMtness: Kathryn C. HymasV,ROCKY MOUNTAIN-ApoltteA
! A DTVTSICN OF mFTORP 2013 ldaho lrrigation Post Report
According to Idaho Falls climate reports8, both the summer and spring were warmer and drier than
normal. Average temperatures were warrner in20l3 by 5 degrees in June, 5.8 degrees in July and 4.7
degrees in August.
There were 27 days in July and 23 days in August with the high temperature above 90 degrees and 30
days each month were sunny and clear.
Average precipitation for June and July, and August is 2.22 inches in normal years. The actual
precipitation total for June, July, and August 2013 was 1.08 inches,49oh of normal.
A comparison between 2012 and 2013 summer weather is shown in Figure 9. A higher temperature peak
is seen in2013 than in2012. The scarcity of growing season precipitation in 2013 can be seen Figure
10.
Summer 2Ot2-20L3 Weather Comparison
' 0.6
0.4
. r 2012 Daily Precip., inches
I 2013 Daiiy Precip., inches
-.'", 2012 Daily Hrgh Temp, degrees f
o
c
c
0.2
ll
.l
l
Iil
*2013 Oaily High Ternp, degrees f
- -- i- -'"------ --*
Irllttltlllrtt-ltttttlttlllrrlllr'I t,l , tl I
17-Jul 24lui 31-Jul 7-Aug 14-Au8 21-Aug 28-Aug
0.1
l-May 8-May 15-May 22-May 29May 5-Jun
Figure 9, Summer 2012 and 2013: Weather Comparison
8 Weather data is shown for ldaho Falls by the Pocatello area branch of the National Weather Service for the summer of 2013
Field Engineering Page 9 of2l I 1/201 3
ROCKY MOUNTAIN
nPH,E**-
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Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
2013 ldaho Irrigation Post Report
Rain Accumulation
from June 1st to August 31st
4.5
4
3.5
2.5
2
a.)
1
0.5
0
I Seasonal Average
s Rain Accunrulation
Figure 10, rain accumulation in southeastern ldaho
Field Engineering Page l0 of21 1t/2013
ROCKY MOUNTAIN
n*o,Hm""
E,hi b itTr::Y Y"iTll! "'"Xr"JCase No- PAC-E-14-07
Witness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
Idaho Transmission System
Most of Rocky Mountain Power's southeastern Idaho irrigation customers are served by circuits that
originate at one of the eight major transmission substations in the area. These transmission substations
and the lower voltage distribution substations and circuits function as a system to supply power to about
9l%o of all irrigation loads in Idaho. The transmission substations, all in the Snake River Plain in
southeastem Idaho, are Amps, Scoville, Big Grassy, Bonneville, Cinder Butte, Goshen, Jefferson and
Rigby. Similar to 2012, the eight substation 2013 composite loading started earlier in the summer and
set a slightly higher peak than 2011. The 2013 load peak was slightly higher than20l2 and 2011. See
Figure I 1.
Most of the variability portrayed in the graph is due to weather and the maturation period of the crops
growr, each individual year may fluctuate drastically.
8 substation composite loading for ldaho
. 2013 Load Control Days
2011 Daily Peaks
-2012
Daily Peaks
-2013
Daily Peaks
oq
Figure 11, 8 substation composite loading
Field Engineering Page ll of2l t1/2013
ROCKY MOUNTAINplOWER
E hibittTY Y,"sTlll :'"X'1
Case No. PAC-E-121-07
\Mtness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
IRRIGATION LOAD CONTROL PROGRAM DBTAILS
Irrigation Load Control is offered to irrigation customers receiving electric service on Schedule 10,
Irrigation and Soil Drainage Pumping Power Service. Participants allow the curtailment of their
electricity usage by working directly with a third party administrator, EnerNoc. Participants' irrigation
equipment is set up with a dispatchable two-way control system giving the Company the ability to
dispatch load control events. Participants are provided a day-ahead notification in advance of control
events and may opt-out of dispatch events as needed. The 2013 curtailment events were not in response
to limitations on ldaho's substations or transmission systems. Capacity exists to serve all connected
irrigation customers in Idaho. Rather, the curtailment events are due to other factors affecting the
broader system.
Load control events in 2013
The 2013 Irrigation Load Control Program was available for 52 hours from June 1Oth to August l6th.
Rocky Mountain Power dispatched ten irrigation load control events and one test event on June 4,2013.
Idaho load control events for 2013 ranged from 79 megawatts to 167 megawatts as recorded by
Company SCADA data. The median curtailed load dispatch was 135 megawatts.
Table 1, Load Control Event Dates and Data *Amps and Camas Subs excluded from dispatch
The program is estimated to have curtailed I l5 megawatts of load on July 1,2013, between 3 p.m. andT
p.m. Mountain Standard Time, the peak day (See Figure 12). Due to some isolated system concems,
irrigation load control participants served from the Camas and Amps substations were excluded from the
load control curtailment event on the peak day. It is estimated an additional42 megawatts (157 total)
would have been curtailed if all participating customers were included in the load curtailment dispatch.
Date
opt-outs
(MW)
Times (MPT)
Reductions
(MW)Dispatch Factors
611812073 2.6 3pm-7pm 13s High temp, system balancing
6128/20L3 6.5 3pm-7pm 153 Hieh temp, svstem balancing
7/L/20L3*11.9 3pm-7pm 115 Hieh temp, system balancing
7l2l2OL3 20.5 3pm-7pm 160 Hish temo. svstem balancine
713/2073 22.5 3pm-7pm L67 Hieh temo. svstem balancine
7 /9/2073 22.5 3pm-7pm 1.54 Hish temo. svstem balancins
7 /LO/20L3 9.3 3pm-7pm r62 Hieh temp. svstem balancine
7h8/20L3 16 3pm-7pm 145 Hish temo. svstem balancins
7l2sl20L3 13.8 3pm-7pm 79 Hieh temp. svstem balancine
7/26120L3 L2.8 3pm-7pm 82 Hieh temp. svstem balancine
Field Engineering Page l2 of2l 1t/2013
ROCKY MOUNTAIN
NHYF*-
=,,,, onl,TY I"1Tl1l :'"X,"J
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
7 I AL I 2013 Curta ilment*
>EE>=>>= >> >=E=EEE>>>=> EE
EE BEEEEE EEEEEEEEEEEEEE EEd N (n =f !^ ro F @ ol p
=
S r-{ N rn st'n ro N o0 o 3 E S
Projected load without load control
Figure 12, July 1st load curtailment profile
rData from Hourly Data of System Loading for RMP summer 2013.
Field Engineeing Page l3 of2l I 1/201 3
ROCKY MOUNTAIN
POI'VER
E,h i b*Xr"":Y Y""sTl?? :r"ffJ
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
System Concerns with Idaho Irrigation
Harmonic lssues
Harmonic pollution continues to be a problem. Since 2008, Rocky Mountain Power has actively worked
to mitigate harmonic pollution in ldaho. The largest contributors to the harmonic pollution on Rocky
Mountain Power's irrigation feeders are unfiltered variable frequency drives used on large irrigation
pumps. NonJinear loads used in potato storage or processing also contribute to harmonic pollution.
The number of pivots adversely affected by harmonic pollution increased in2013. See Figure 13.
Pivot system problems
r Number of pivots that walked off their intended paths
t4
12
10
8
6
4
2
0
2010
Figure 13, Pivot system problems
A detailed discussion about harmonic pollution can be found in Appendix I.
Load Control - Voltage Issues due to Load Control Events
Since change in load on the power system affects the system voltage, an irrigation load control event
that reduces load affects system voltage. Load reduction causes the power system's voltage to increase,
sometimes above the prescribed range of ANSI C84.1 . Although equipment with automatic controls is
used to adjust voltage, it does not react instantly to changes in voltage on the system, and may take up to
several minutes to adjust the voltage to the proper range in response to severe changes.
The following factors contribute to the number of ANSI range A voltage violations:
Field Engineering Page l4 of2l I 1/2013
V,ROCKY MOUNTAIN-flpg11 Ep\ q o,vrstor of B.oncoap
E,hibitl::YY"iTl13:'"X'"J
Case No. PAC-E-1+07
Vvitness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
Irrigation loads are often geographically concentrated in particular areas of the network.
Curtailing large blocks of participating irrigation load concentrated on a single circuit or a single
substation at the same time increases the magnitude of the voltage change.
Circuits serving predominately irrigation load with a high percentage of Inigation Load Control
Program participants will magnify the voltage rise on the circuit during an irrigation load control
event.
Metering at an irrigation customer site shows the voltage levels during a typical load control event
where the entire block of load is curtailed at the same time. See Figure 14.
Figure 14, Typical load controlled event on Hamer Sub
Early in the 2013 growing season voltages in excess of the ANSI C84.1 Range A parameters occurred
and resulted in damage claims from customers due to high voltage failures of their equipment. The
condition was corrected upon discovery. EnerNoc altered the load curtailment events to drop load in
stages over a l0 minute period instead of the entire load instantaneously. Demand Side Management's
objective is to reduce load in large blocks simultaneously in order to minimize system peaks and to
maximize the energy available to market. Operation's objective is to maintain system voltage in the
proper range without excursions, which is difficult to do when load is reduced in large blocks. The
adjustment to the load curtailment implemented by Rocky Mountain Power successfully mitigated the
voltage excursion seen in the early part of the 2013 growing season.
o
a
710312013 load control event
Customer voltage on Hamer 11
530
- - ANSI Range A Max
-Voltage
NominalVoltage
Hour
520
510
{,f soo
490
480
470 rr) r.. o) t-{ (n u.) r.. Gl Fl (Y) rf} 1.. cn rl (n l^<i <. $ rn Ln ta, rfi tt O O O O O Fl Ft ri+ + !+ S + + $ $ r' rr) ln !n fl l'l f) !A
F{ -{ Fl e{ ei ei -{ F.{ F{ F{ F.{ F{ Fl el -.1 J
Field Engineering Page 15 of2l t 1/2013
Rocky Mountain Power
Exhibit No. 1 Page 467 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. HymasJ,ROCKY MOUNTATN-(POWER
\ a OIVISION OF &CTFlcOnP 2013 ldaho lrrigation Post Report
During the past few years Rocky Mountain Power has completed the following activities to address
voltage issues related to irrigation load control switching:
o Installed a 3-step capacitor bank on the 69 kilovolt bus at Big Grassy substation before the 201 I
irrigation season;
o Replaced manual capacitor banks with automatic sensing capacitors that switch automatically to
maintain acceptable voltage levels. e
o Forty Six automatic switched capacitors were installed and 59 manual capacitors were
removed.
o This work was completed on 14 circuits before the start of the 2012 imgation season.
o Installed metering inside seven different substations and on four different customer accounts on
irrigation circuits to understand and monitor voltage issues
The stepped capacitor bank and automatically switched capacitor banks are working well. Voltage
swings on the 69 kilovolt bus at Big Grassy substation were less after this work than in the years before
it was done. See Figures 15 and 16.
Transmission Voltage at Big Grassy Sub 2009, 2010 and 2011
-upper69kvliftit -bwd69kvlimit
82009
-2010 -201:
l-May 8-May 15-May 22-May 29-May s-Jun 12-Jun 19-Jun 25-Jun 3Jul 10-iul 17-.lul 24-Jul 31-Jul 7-Aug 14-Aug 21-AuC 28-tuC
Figure 15, Big Grassy Voltage, 3-step capacitor was installed before 2011 season
' P..t of . settlement reached in 2011 with the ldaho Commisslon staff, the ldaho lrrigation Pumper Association, and Rocky Mountain Power
1 ;"!,.
ii'
Field Engineering Page l6 of2l I 1/201 3
Rocky Mountain Power
Exhibit No. 1 Page 468 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. HymasROCKY MOUNTAIN
POWER 2013 ldaho lrrigation Post Report
Transmission Voltage at Big Grassy Sub 20L2 and 2013
-upp$Sgkvlimit -Lomr6gkvlimit
e2012
-2013
I
+ # * + + * + # + f # : .3 i i ; : _= i : j j - r i ; i i i i a i i i i i 3 i i i ii+Fom6oNh€i iiiNaN6d No66o
Figure 16, Big Grassy Voltage after line-type controlled capacitors were installed
Field Engineering Page I7 of21 I 1/201 3
ROCKY MOUNTAIN
POWER
=,n, ontTY I""nTli! :'"XrT
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
2013 ldaho Iwigation Post Report
CONCLUSIONS
The report analysis leads to these conclusions:
o Idaho's overall peak load was 814 megawatts on July 1,2013 at l0 pm MST of which 302
megawatts was from irrigation customers. The irrigation load control program shifted the peak to
a later time period in the evening.
The Idaho irrigation load represents a significant percentage of Idaho's peakload,3To/o.
The Inigation Load Control Program was dispatched ten times in 2013. The median estimated
curtailed load dispatch was 135 megawatts.
The distribution system improvements that were added prior to the 2012 irrigation season
continue to minimize the voltage swings on the 69 kilovolt bus at Big Grassy substation.
Voltage excursions have occurred during load control events. However, the capacitor bank
mitigation efforts from previous years and the staged load dropping implemented this year
minimized the number of voltage excursions.
o Harmonic pollution is a growing problem on Rocky Mountain Power's inigation distribution
circuits.
o Load curtailment must be managed in small increments rather than large blocks. This allows
voltage control equipment time to react to the change in loading and adjust the voltage to stay
within ANSI C84.1 Range A parameters.
RECOMMENDATIONS
o Continue efforts to make irrigation load control events a win-win for customers, the State of
Idaho, and the power company.
Distribution circuit and voltage monitoring is required to ensure proper system operation.
Continue efforts to educate irrigators about variable frequency drives, harmonic pollution
mitigation and customer's responsibility for their own systems.
o
a
o
a
Field Engineering Page l8 of21 1t/20ti
Rocky Mountain Power
Exhibit No. 1 Page 470 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. HymasROCKY MOUNTAIN
POWER
2013 ldaho Irrigation Post Report
APPENDIX t
Harmonic Pollution
Harmonic pollution is unrelated to the Idaho's Irrigation Load Control Program. However, it is related
to irrigation systems and is briefly discussed here. The company's mitigation effort to significantly
reduce harmonic pollution appears to be working as irrigation systems modified to minimize harmonics
are not creating problems for the customers or the power company. However, harmonic issues in the
area continue to be a concern to Rocky Mountain Power.
Twelve different pivot systems on six different circuits walked off of their intended paths in 2013. A
graphical view of the offending pivots is shown in Figure A-1. Many of the pivots left their intended
path multiple times. One of these pivots broke a 3-phase tangent pole on Moody #12 and caused a 6.9
hour outage to l7 customers on June I |th,2Ol3.
J Red spot shows loetion of pivots that walked off of intended path
t
Si Ardsv Sub
.- I
Figure A-1, Pivot systems that walked off their intended path
-5
'-, 1
Field Engineering Page l9 of2l il/2013
v.RocKY MOUNTATN-(1POWER
\ A olvrstoN or PactrrcoiP
=- n, o ntllY I""nTl1? :'"X'"J
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
2013 ldaho lrrigation Post Report
Harmonic pollution caused by unfiltered variable frequency drive pump loads leads to the irrigation
center pivot swing arms steering away from their pre-determined paths of travel. An electrically charged
trace wire is buried in the ground that provides the sensors in the center-pivot swing arms a path to
follow. The signal on the trace wires is similar to the l3th, l7th, and 19th harmonics currents produced by
unfiltered variable frequency pump motor drives. The antenna array used by the pivot system can be
influenced by the elevated harmonic levels. This can cause the swing arm to steer away from the desired
path. Figure A-2 shows a typical antenna array system that is used to follow the buried trace wires.
Figure A-2, Typical Center Pivot Antenna Array
Efforts to mitigate the issues from harmonic pollution included several strategies. First. Since 2008
Rocky Mountain Power has provided feedback and education to irrigators and electrical contractors
regarding the importance and application of filtering for variable frequency drives to insure IEEE 5 l9
compliance.
Second, in201l, Rocky Mountain Power reviewed susceptibility issues with center-pivot system
designers and manufacturers. According to the center-pivot manufacturers, the designs have successfully
worked for the last 30 years with very few problems and they were thus unwilling to change their swing
arm tracking design. Further. the incompatibility of harmonic guidance systems and harmonics from
variable frequency drives has not been well understood since variable frequency drives were not widely
used in irrigation systems until recent years. In the future GPS tracking swing arrns are expected to
replace current technology which will help alleviate the existing guidance problem.
Third. Rocky Mountain Power monitors the status of distribution line capacitor banks. Capacitors act as
frequency sinks for higher order harmonics. Thus, if a capacitor bank is not working correctly, there is a
greater chance the harmonic pollution levels on the system could affect tracking of the center-pivot
swing arm.
Last, Rocky Mountain Power is working towards installing GE KV2C meters for irrigation customers in
2014. These meters are capable of measuring and storing harmonic pollution data and downloading the
data for evaluation to determine compliance with harmonic levels. Roughly 780 irrigation revenue
meters will be replaced with the GE KV2C meter over the next three years. The proposal to install these
Field Engineering Page 20 of 2 I It/2013
ROCKY MOUNTAINpolrvER
E-h.bi tTY Y""sTl?! :'"Xr"J
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
2013 Idaho lrrigation Post Report
meters is still in the planning stage, but should begin implementation before the start of the 2014
growing season.
Rocky Mountain Power will continue to monitor harmonic issues and address customer complaints in a
prompt and efficient manner. The company expects its mitigation eflorts along with effective customer
participation will reduce harmonic pollution. A growing company/participant parhrership is needed to
provide reliable electric service and improved customer satisfaction.
Idaho Crops Load Detail
The primary crops grown in the Rocky Mountain Power service territory in southeastern Idaho are
alfalfa barley, potatoes, and wheat. Wheat, barley, and other grains are watered typically in late May,
June and July. Watering stops in late July or early August to allow the grains to dry for harvest. Potatoes
are watered through the whole summer. Alfalfa is also watered through the entire summer except during
intervals where it is cut, dried, and harvested. These dates vary each year, but generally occur in mid to
late June and late July to early August.
Figure A-3 represents the periods of highest load potential using ten-year historical data from the
watering periods of the most common crops in the program. The 2010,2011,2012, and 2013 load data
for the Big Grassy substation which primarily serves irrigation load is included to denote the variability
for any given year.
i itofro -
II
I
90 08
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Field Engineeing
I lqr xS lun l1,uft lg"lux 6,,u1
Page2l of21 I 1/2013
Figure A-3, ldaho Crop Detail
ROCKY MOUNTAIN
POWER
.,n,0n1"":Yl,iTl?l:'"X,"J
Case No. PAC-E-14-07
VMtness: Kathryn C. Hymas
2013 lduho lrrigation Post Report
Most of the variability portrayed in the graph is due to weather and the maturation period of the crops.
Alfalfa, accounting for 5lYo of the crop within the Idaho Irrigation Load Control program, is one of the
crops that contribute to this variability since watering discontinues two to three times for harvesting.
Although average crop and weather pattems provide a good indicator of what may occur, each
individual year may fluctuate drastically.
Field Engineering Page 22 of 2l 1t/2013
Rocky Mountain Power
Exhibit No. 1 Page 474 of 495
Case No. PAC-E-1+07
'\Mtness: Kathryn C. Hymas
Yffifill',rouNrArN
Appendix 7
Idaho Measure Installation Verifications
Rocky Mountain Power
Exhibit No. 1 Page 475 of 495
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
Idaho Measure Installation Verifications
Low Income Weatherization
All projects
o All measures are qualified through US Department of Energy approved audit tool.o 100 percent inspection by agency inspector of all homes treated, reconciling work
completed and quality (corrective action includes measure verification) prior to invoicing
Company.
o Community Action Partnership Association of Idaho (CAPAI) and state inspector follows
with random inspections.o Company program manager joins CAPAI and state inspectors during their monitoring
session.
Home Energy Savings
Site inspections by Program Administrator stafffor the following retrofit measures Q 5 percent)
o Duct sealing and insulationo Duct sealingo Gas furnace with electrically commutated
o Heat pump best practices installation ando Heat pump tune-upso Heat pump water heaterso Insulation. Windows
Pre and post site inspections of 100 percent by Program Administrator staff of all multi-family
projects.
No site inspections are conducted for the following measures. However all post-purchase
incented measures undergo a quality assurance review prior to the issuance of the
customer/dealer incentive and recording of savings (i.e. proof of purchase receipt review) and
eligible equipment review. Additionally, customer account and customer address are checked to
ensure the Company does not double pay for the same measure or double count measure savings.o Air conditionerso Clothes washerso Dishwashero Ductless Heat Pumpo Evaporative coolerso Ground Source Heat Pump
o Heat pump upgrades/conversionso Light fixtureso Refrigerators / Freezerso Water heaters (excluding heat pump water heaters)
motor (ECM)
proper sizing
E,,hibitt::YY""sTl?::r"XrT
Case No. PAC-E-1+07
Witness: Kathryn C. Hymas
Other measures
o CFLs and LED's - retail channel, manufacturer agreements and program administrator sales
record reviews of qualifuing equipment. Invoicing and retail pricing is administered by
program administrator.
Refrigerator Recycling
Company hires an independent inspector to phone survey > 5 percent program participants and to
site inspect > 5 percent of program participants in order to verifuing program participation,
eligibility of equipment, that vendor pick-up procedures are followed (equipment is disabled at
site, kits distributed, etc.) and to survey customer experience.
FinAnswer Express
For projects delivered by third party program administrator
Lighting projects
o Retrofits - 100 percent pre- and post-installation site inspections by third party consultant
of all projects with incentives over a specified dollar amount. Project cost documentation
reviewed for all projects.
o New construction - 100 percent post-installation site inspections by third party consultant
of all projects with incentives over a specified dollar amount.
o I percent of post-installation site inspections by program administrator of projects with
incentives under a specified dollar amount.
Non-lighting projects (typically upgrade/listed measures, custom measures)o 100 percent of applications with an incentive that exceeds a specified dollar amount will
be inspected (via site inspection) by program adminisffator.o A minimum of a specified percent of remaining non-lighting applications will be
inspected, either in person or via telephone interview, by program administrator.
For Company project manaeer delivered projects (liehting and non-lightine)
Lighting and non-lightingo 100 percent prelpost-installation site inspections by third party consulting engineering
firms, invoice reconciled to inspection results.
Energy FinAnswer
All projectso 100 percent pre and/or post-site inspections by third party engineering consultant,
inspection is reconciled with project invoice for energy efficiency retrofit measures
provided by customers. No pre-inspection for new construction.o Most projects have a commissioning requirement.
Rocky Mountain Power
Exhibit No. 1 Page 477 of 495
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
All Programs
As part of the third-party program evaluations (two-year cycle) process, the Company is
implementing semi-annual customer surveys to collect evaluation-relevant data more frequently
to cure for memory loss and other detractors such as customers moving and data not be readily
available at evaluation time). This will serve as a further check veriffing customer participation
and measures installed.
Additional record reviews and site inspections (including metering/data logging) is conducted as
part of the process and impact evaluations, a final verification of measure installations.
Rocky Mountain Power
Exhibit No. 1 Page478 of495
Case No. PAC-E-14-O7
Wtness: Kathryn C. Hymas
\FE[[il',rouNrAIN
Appendix 8
Idaho Program Evaluation
Recommendations and Responses
Rocky Mountain Powet
Exhibit No. 1 Page 479 ot 495
Case No. PAC-E-1+07
Vwness: Kathryn C. Hymas
Idaho 2013 Evaluations
Program Evaluation Recommendations and Company Responses
Evaluation reports provide detailed information on the process and impact evaluations performed
on each program, summarizing the methodology used to calculate the evaluated savings as well
as providing recommendations for the Company to consider for improving the process or impact
of the program, as well as customer satisfaction.
Outlined below is a list of the programs, the years that were evaluated during 2013 and the third
party evaluator who completed the evaluation. Program evaluations are available for review at
rnvrr,.pacit'icoro. com/es/dsm/i daho.html
Program Years Evaluated Evaluator
See ya later, refrigerator 2011-2012 The Cadmus Group
FinAnswer Express 2009-2011 Navigant Consulting Inc.
Irrigation Energy Savers 2009-2011 Navigant Consulting Inc.
Energy FinAnswer 2009-2011 Navigant Consulting Inc.
Company responses to the program recommendations contained in the 2009 - 201 I evaluations
are provided below.
The third part,v evaluator's recomnrendaticlns and Company's responses are provided in the
below Tables:
'i ahle 1
See va later. reiriueralorlJ. Evaluation Rec{rmrnei-tdations
Evaluation Recommendations Rockv Mountain Power Action Plan
Rocky Mountain Power should consider adjusting
its expected per-unit savings for future program
years to reflect the evaluated per-unit gross savings
values of 1,022 kWh for refrigerators, 1,033 kwh
for freezers, and 47 kWh for kits, as found in this
evaluation.
Refrigerator and freezer savings were updated for
2014 reporting based on the evaluation results. Kit
savings were updated using hours ofuse, in-service
rates and waste heat factor from the evaluation and
further modified based on EISA lumen equivalency
for a oer kit savinss of 30.23 kWh.
The program administrator and Rocky Mountain
Power should continue with improved tracking of
Kit tracking was implemented at the beginning of
2013.
Rocky Mountain Power
Exhibit No. 1 Page 480 of 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
l"ablc l
l: in.,\ n s rve r [:, r p re s s L:v a i Lr a t i an lt e c o m nr i: n ci aX i o n s
Evaluation Recommendations Rocky Mountain Power Action Plan
enerry-savings kit delivery, including recording
whether or not a kit was delivered. This change has
already been implemented beginning in 2013.
Rocky Mountain Power should consider revising
the measures provided in the kits, as the Energy
Independence and Security Act of 2007 (EISA)
standards in2014 will lead to decreased savings for
60-watt replacement CFLs. If kit measures are
revised, Rocky Mountain Power should update
expected per-unit savings for kits accordingly.
Refrigerator and freezer savings were updated for
2014 reporting based on the evaluation results. Kit
savings were updated using hours of use, in-service
rates and waste heat factor from the evaluation and
further modified based on EISA lumen equivalency
for a per kit savings of 30.23 kWh.
For future cost-effecti veness cal cul ati ons, Cadmus
recommends that Rocky Mountain Power update
measure lives to align them with the values adopted
in the most recent Regional Technical Forum
(RTF) measure workbooks:
Refrigerators: 7 years
Freezers: 5 years
CFLs (kits): 6 years
Technical Reference Library has been updated
based on evaluation recommendations for measure
lives.
Evaluation Recommendations Rockv Mountain Power Action Plan
Recommendation 1. Review marketing messages
and channels to engage commercial
andindustrial customers who are not aware of
efficiency opportunities. Half of participants and
three-quarters of non-participants did not believe
there are additional opportunities to improve
electric efficiency at their firm. Marketing
collateral that educates and challenges customers to
reevaluate their position may be necessary to reach
these customers. Reaching new customers is
essential to ensure long-term success ofthe
program in cost-effectively meeting energy savings
soals.
The Company is increasing its efforts to reach
small and mid-sized business customers and this
evaluation feedback is informing the effort and
customer communications.
Recommendation 2. Continue to nurture and
develop the trade allv network. Vendors are a
The Company continues to invest in nurturing and
developins the trade ally network.
Roclq Mountain Power
Exhibit No. 1 Page 481 of495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
critical program delivery mechanism for post-
purchase incentive programs, like FinAnswer
Express. Third-party pro$am administrators,
serving as Trade Ally Coordinators, should
continue their efforts to develop and nurture strong
vendor relationships and to build additional vendor
relationships. Strong relationships encourage trade
ally vendors to take the time to market the program
effectively.
Table 3
Irrigation Inerg3.' Sar,els i:vaiuatlon Recomnrencialions
As a result of the evaluation recommendations, the Company filed an Application to revise
Schedule 155, Irrigation Energy Savers program. To see the details of the recommendations,
please refer to the program evaluation report using the web link above.
'l'alrie -l
Energr' [:inAnsrver Evaiuation l{econrmenciation-c
Evaluation Recommendations Rockv Mountain Power Action Plan
Recommendation 1: Consider revised marketing
strategies to increase lead generation. More than
three-quarters of eligible industrial non-participants
did not believe there were further actions they
could take to improve efficiency at their firm.
Customers who do not believe there are actions that
they can take may not respond to traditional
approaches promoting energy effi ciency programs.
Project managers, program managers, and enerry
engineers understand the potential for cost-
effective improvements across industries. Data
from previous projects can be used to identiff cost
savings and operational improvements from
common efficiency efforts in particular industries
in order to interest more eligible customers.
Increasing participation is important to ensure
continued Drogram success.
eBlasts" were added to the marketing strategy in
2013. eBlasts emailed to Rocky Mountain Power
business customers included the following:. February 2013 - eBlast on linear fluorescent
lighting upgrades. July 2013 - eBlast on reducing cooling costsr October 2013 - eBlast on food service
equipment incentiveso November 2013 - eBlast on improving heating
system performance
ln addition, the company newsletter, Energy
Connections, is distributed quarterly via email and
includes articles on energy efficiency.
Recommendation 2: Closely track project status.
Closely tracking the status of projects should alert
the project and program managers when savings
goals may not be met by existing projects. The
Drogram staffcould then determine altemative
Updated tracking and reporting system has been
implemented to more closely track projects and
provide automated follow up items on open
projects.
Rocky Mountain Power
Exhibit No. 1 Page 482 01 495
Case No. PAC-E-14-07
Wtness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
strategies to meeting savings goals. Depending on
the projects in the pipeline at the time, the approach
may be to seek out new participants, to encourage
project completion, or to encourage customers to
take action on measures identified in their EARs
that were not currently being addressed. Ensuring
that projects are completed as expected decreases
uncertainty and risk for projects where Rocky
Mountain Power has already invested time and
resources.
Recommendation 3: Clarify baseline conditions,
particularly for lighting projects. There were two
lighting projects in the Energy FinAnswer program
impact evaluation sample which did not include
any description of baseline equipment. Project files
simply stated that premium efficiency T8s were
being installed, and no calculations were provided.
Without information on any removed fixtures, or
baseline assumptions in the case of new
construction, it is not possible to accurately
determine how savings were calculated for the
projects.
Both of the identified project were new
construction projects as such an industry standard
or energy code baseline was applied , additional
documentation of baseline will be provided for
new construction projects to more readily identifli
baseline used for reported energy savings.
Recommendation 4: Include energy and demand
savings calculations in a spreadsheet format. By
providing this information in one consolidated
location, future evaluation efforts will be more
efficient and reduce the potential for comparing
verified savings to incorrect or outdated project
assumptions.
o Although each project properly documented the
reported enerry and demand savings estimates, the
absence of savings calculations (particularly for
demand savings) reduces the transparency of
reported savings, along with the effrciency of
evaluation efforts. Providing both the input
assumptions and savings calculation methodologies
will ensure the comparability and accuracy of
reported and evaluated savings and will reduce
associated evaluation costs.
o Include the clearly identified final Energy
Savings table in project files for the evaluation. The
data should include both baseline and current
energJ and demand usage as well as savings
estimates. Utilizins consistent formats based on the
This recommendation has been reviewed and found
to be non-cost effective by the company, complete
files will be provided as a standard practice.
Additional summary reports will not be added for
third party evaluation purposes only.
Rocl(y Mountain Power
Exhibit No. 1 Page 483 of 495
Case No. PAGE-1+O7
'Vl/itness: Kathryn C. Hymas
Evaluation Recommendations Rockv Mountain Power Action Plan
FINAL numbers is important for all follow up
activities, and will provide decision makers the key
information needed to quickly assess the situation
and take appropriate action relative to the
inspections conducted. It is noted that the key
elements are included in the documentation for
each project but it is often difficult to identiff the
final set ofparameters used because the project
files capture multiple changes/revisions to the
application process.
Roclry Mountain Power
Exhibit No. 1 Page 484 of 495
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
vRocKYMOUNTAIN-<POWER
\ a orvrsroru oF PAcrFrcoBP
Appendix 9
Idaho Low Income Weatheization
E-h i bitXr"":Y Y"iTlll :'"ffJ
Case No. PAC-E-1+07
Wtness: Kathryn C. Hymas
The Income Criteria for Idaho is set at 150% of the Department of Health and Human Services
Poverty Guidelines, and is shown below.
50% of Povertv Guidel nes
ramily Size
Monthly
Income
Limit
i Month
ncome Limil
1 i ,436 $ 4,309
I ,939 $ 5,817
12.442 $ 7,325
12.944 $ 8,833
i3"447 $10,341
)$3,950 $11,849
i4,452 $13,357
i4,955 $ 14,865
lach
A.dditional
Member
$503 $ 1,508
These income levels were effective as of July 1,2013.
Rocky Mountain Power
Exhibit No. 1 Page 486 of 495
Case No. PAC-E-1+07
Ufrtness: Kathryn C. Hymas
YffiOUNTAIN
Appendix 10
Trade Ally's
Rocky Mountain Power
Exhibit No. 1 Page 487 of 495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
V,.ROCKY MOUNTAIN
XPowER
The following is a lrst of contractors, distributors and other businesses participating in Rocky Mountain Power's Energy Efficiency Alliance
displayed in random order (unless sorted by the user) based on the search criteria selected. This listing is provided solely as a convenience
to our customers. Rocky Mountain Power does not warrant or guarantee the work performed by these participating vendors. You are solely
responsible for any contract with a participating vendor and the performance of any vendor you have chosen.
An asterisk (-) indicates Rocky Mountain Power Outstanding Contribution Award winning trade allies in 2006, 2007. 2008, 2009, 2010,2011
andlot 2012
Search Criteria:
Search Resu/fs.' 92 - Date and Time: A4/11/2014 1A:28:54 AM
Selected State(s):
Specialfes:
Business Type:
230 West 700 South
Salt Lake City, UT
Phone:[phone]
Website: rescoslc.com
D.W. Electric
4565 E. 75th N.
Rigby, lD
Phone: [phone]
244 W 300 N
Suite 200,
Salt Lake City, UT
Phone: [phone]
Platt Electric Supply.
919 Pancheri Street
ldaho Falls, lD
Phone:208-524$171
Electrical Wholesale Supply Co., lnc
- Blacktoot
560 Jensen Grove Rd.
Blackfoot, lD
Phone: [phone]
Website: www.ewsminc.com
Bateman-Hall, lnc.
1405 Foote Drive
ldaho Falls, lD
Phone: [phone]
Website: www.bateman-hall.com
Precision-Paragon [P2]
23281 La Palma Ave
Yorba Linda, CA
Phone: [phone]
Website: www,p-2.com
Business Type Join DateDistributor 1011512013
ldaho
Lighiing
HVAC - unitary
HVAC - evaporative
Motors and VFDS
Controls
Building envelope
Appliances
Office Equipment
Food Service
Compressed Air
Farm and Dairylrigation
Oiher
--ANY_
Specialties
Lighting
Specialties
Lighting
Restaurant and Store Equipment Specialtiescompanv *BxT8i:""
Projects
Completed
Colvin Engineering Associates, lnc. Specialties
Business Type Join DateContraclor 0510112011
Business Type Join DateArchitect 0412912013
Business Type Join DateDistributor 01/01/2009
HVAC - evaporative Engineering Firm
HVAC - unitary
Other: Other Specialty
Projects
Completed
1
Projects
Completed
Projects
Completed
10
Proiects
Completed
null
Specialties Business Type Join DateControls Distributor 0912212012
Lighting
Motors and VFDS
Specialties
Other: Other Specialty
Specialties
Lighting
Business Type Join DateContractor 0211812014
Business Type Join Date
Manufacturer - Rep 0311312013
Other: Manufacturer
Proiects
Completed
Projects
Completed
O20l2RckyMountainPdGr..divLionofP.clfiCorp andpanof Miilmric.nErergyHoldlngsComp.ny
Rocky Mountain Power
Exhibit No. 1 Page 488 of495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
ROCKY MOUNTAIN
POIYER
Town & Country Electric, Inc.
1223 11lh Ave. North
Nampa, lD
Phone: [phone]
Website: town-and-country-electric. com
Electrical Wholesale Supply Co., lnc.
- Rexburg
899 Jetstream Dr.
Rexburg, lD
Phone: [phone]
Website: www.ewscoinc.com
Tirrell's Electric, lnc.
770 E. Sunnyside Rd.
ldaho Falls, lDPhone:208-524-2456
Wheeler Electric
469 West 16th St.
ldaho Falls, lD
Phone: 208-522-'1906
Website: wheelerelectric.com
Realwinvvin, lnc.
1 926 Arch Street, 4F
Philadelphia, PA
Phone: 2'15-732-4480
Website: www.realwinwin.mm
American Mechanical Sysytems
Service, LLC
7530 South State Street
Midvale, UT
Phone: [phone]
Website: www.ams-ut.com
H-C Oesign & Consulting
P.O. Box 10545
Bozeman, MT
Phone: [phone]
Case, Lowe & Hart, lnc.
2484 Washington Blvd.
Suite 510,
Ogden, UT
Phone:80'l-399-5821
Website: www.clhae.com
Lewi$ Corporation
15136 Hunziker
Pocatello, lDPhone:208-238-1202
Website: lcorp.com
3M Company
3M Center Bldg 235-2S-27
St Paul, MN
Phone: [phone]
Website: www. 3m. com/windowfi I m
Consolidated Electrical Distributors*- Logan, UT
636 N. 600 W.
Logan, UT
Phone: [phone]
Specialties
Appliances
Building envelope
Controls
Food Service
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDs
Office Equipment
Specialties
Controls
HVAC - unitary
Motors and VFDs
Specialties
Food Service
Specialties
Building envelope
Compressed Air
Controls
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDs
Specialties
HVAC - unitary
Specialties
Lighting
Specialties
Controls
Lighting
Motors and VFDs
Specialties
Lighting
Specialties
Lighting
Business TypeContractor
Business Type
Distributor
Business Type
Contractor
Business Type
Contractor
Join Date
0'1/01/2009
Join Date
09122t2012
Join Date
03/01/2009
Join Date
01101t2007
Join Date
10114t2013
Join Date
11t30t2012
Join Date
07101t2013
Join Date
05117t2013
Join Date
o8t01t2008
Proiects
Completed
Projects
Completed
6
Projects
Completed
1
Projects
Completed
5
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Business Type
Other: Energy
Efficiency lncentive
Administration and
Consultation
Business Type
Contractor
Business Type
Manuhcturer - Rep
Business Type
Architecl
Engineering Firm
Business Type
Contractor
Business Type
Distributor
Projects
Completed
Projects
Gompleted
Specialties
Farm and Dairy
lrrigation
Lighting
Join Date Projects03t26t2005 Completed
42
Specialties Business Type Join Date
Building envelope Manufacturer - Rep 0412512013
Roclry Mountain Power
Exhibit No, 1 Page 489 of495
Energy Efficiency Alliance
Witness: Kathryn C. Hymas
VROCKY MOUNTAIN
aPowER
L&KMatcoElectric
P.O. Box 7964
Boise, lD
Phone: [phone]
Felt Lighting lnc.
1220 East 3300 South
Satt Lake City, UT
Phone: [phone]
Website: www.feltlighting.com
LEPCO (Leonard Petroleum
Equipment )
P.O. Box '170219
Boise, lD
Phone: [phone]
Codale Electric Supply - Casper
313'l Wood Court
Casper, VVY
Phone: [phone]
Website: www. codale.com
Kaman lndustrial Technologies
525 S. Utah Circle
ldaho Falls, lD
Phone: [phone]
Website: kaman.com
YESCO LLC - Salt Lake City, UT
1605 S. Gramercy Road
Salt Lake City, UT
Phone: [phone]
Website: www. yesco. com
DesignTek Consulting Group, LLC
1600 w. 2200 s
Salt Lake City, UT
Phone: [phone]
Website: www.designtekconsulting.com
Verismic Software lnc.
65 Enterprise
Aliso Viejo, CAPhone:94*222-2287
Website: www.verismic-crm
PVE, lnc
1040 North 2200 West, Suite 100
Salt Lake City, UT
Phone: [phone]
TreeFrog LED, lnc.
7594 North Swansea Court
Eagle Mountain, UT
Phone: [phone]
Website: www. treeft ogled.com
Cooper Lighting
1 121 Highway 74 South
Peachtree, GA
Phone: [phone]
Website: www.cooperlighting.com
Johnson Controls, lnc.
2255 Technology Parkway
West Valley City, UT
Phone: [phone]
Specialties
Appliances
Controls
Lighting
Motors and VFDs
Specialties
Compressed Air
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDS
Specialties
Office Equipment
Other: Other Specialty
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDS
Specialties
Lighting
Specialties
Lighting
Specialties
Controls
Lighting
Specialties
Lighting
Specialties
Lighting
Specialties
Motors and VFDS
Business Type
Contractor
Business Type
Distributor
Business Type
Contractor
Business TypeDistributor
Business Type
Distributor
Join Date
10t01t2011
Join Date
11t27t2013
Join Date
09t24t2012
Join Date
06127t2013
Join Date
09/01/2006
Join Date
09t22t2012
Join Date
11t11t2013
Join Date
01t16D013
Join Date
07t29t2013
Join Date07t29nu3
Join Date
12t13t2012
Join Date
o6t01t2007
Projects
Completed
1
Projects
Gompleted
1
Projects
Completed
1
Projects
Completed
Projects
Completed
Projects
Completed
40
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Specialties
Controls
Lighting
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDs
Business Type
Contractor
Manufacturer - Rep
Business Type
Contractor
Engineering Firm
Business Type
Contractor
Distributor
Manufacturer - RepOther
Business Type
Engineering Firm
Business Type
Distributor
Business Type
Manufacturer - Rep
Business Type
Contractor
Manufacturer - Rep
@412 R*ty iloudqin Piler, . dtoirion of P.cificorp .nd p.n ol MldAmeric.n En.rgy Holdlnil comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 490 of495
Energy Euilciency Elliance
Wtness: Kathryn C. Hymas
ROCKY MOUNTAIN
POUyER
Electrical holesale Supply Co., lnc.
ome Lighting
650 W. Sunnyside Rd.
,daho Falls, iE
Phone: [phone]
Website: www.ewscoinc.com
DiVi Energy, LLC
68 S Main St., Ste 800
Salt Lake City, UT
Phone: [phone]'1
Bradley Engineering
382 Walnut Street
daho Falls, tD
Phone: [phone]
Website: www. bradleyengineering.com
' estern eating Fireplaces
4980 W. :rradley Street
__roise, ilD
Phone: [phone]
llred s lncorporated
1410 Gibson Avenue
Ogden, UT
Phone:[phone]
Website: www.allreds.net
llo ay Commercial Lighting
1420 Grove Street.'oise, IE
Phone: [phone]
Website: www.allowaylighting. mm
Valley lmplement
2'13 West 8th North
Preston, D
Phone: [phone]
Website: valley-implement.com
Lenno .
1 008 w 2780 S
Salt Lake City, UT
Phone: [phone]
Website: lenno:bommercial.com
ePlus reen lnc,Specialties
Office Eouioment
7951 SW 6th Street, Fort Lauderdale Other: Oih6r Specialty
FL 33324
Suite 208,
Ft Lauderdale, FL
Phone: [phone]
Website:
http: //www. eplusgreen. com/pro/inde I ht
ml
Specialties
Controls
Lighting
Motors and VFDs
Specialties
Lighting
Specialties
Lighting
Business Type
Distributor
Business Type
Manufacturer - Rep
Other
Business Type
Engineering Firm
Join Date
09t2212012
Join Date
01t23t2013
Join Date
09t22t2012
Join Date
09/01/2008
Join Date
05/11t2011
Join Date
09t26t2012
Join Date
12t05t2012
Join Date
11t01t2005
Projects
Completed
null
Specialties
HVAC - unitary
Specialties
HVAC - unitary
Specialties
Lighting
Specialties
Controls
Erigation
Motors and VFDs
Specialties
HVAC - unitary
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Projects
Completed'18
Projects
Completed
7
Projects
Completed
Projects
Completed
Projects
Completed
1
Projects
Completed
null
Projects
Completed
Business Type
Contractor
Distributor
Engineering Firm
Other
Join Date Projects01t10t2013 Completed
PC Sales and Ser ice Corp.
1 32 Fairgrounds Road
West iringston, R:t
Phone: [phone]
Website: www. schneider-electric.com
enPro Energy Solutions LLC
1326'l Timberline Pla a
Suite a,
Piedmond, SD
Phone: [phone]
Business Type Join Date ProjectsOther 03t01t2012 Completed
Business Type Join Date ProlectsDistributor 0712912013 Completed
Manufacturer - Rep
Specialties
Lighting
Specialties
Controls
Farm and Dairy
-nigationLighting
tmtoc:ytrountalnPo!€r,adi-3ionotPa6irrcorp sndpsnoaldlm6dcenEnlrgyroHlng!Company
Rocky Mountain Power
Exhibit No. 1 Page 491 of 495
Witness: Kathryn C. Hymas
Energy Emlciency Illiance V.,ROCKY MOUNTAINv(eowen
'- orthern Lights Electric LLC
3473 E. 20th N. Unit A
nlaho Falls, tD
Phone: [phone]
arris ircra t, lnc. DB arris
Lighting Products
1405 W. 800 N.
Preston. lD
Phone: [phone]
Thurgood echanical Ser ice, lnc.
4245 E. 653 N
Rigby, D
Phone: [phone]
oney ell lnternational
2371 S. Presidents Way Suite A
Salt Lake City, UT
Phone:[phone]
Website: honeywell.com
Energy . . anagement Corporation
501 West 700 South
Salt Lake City, UT
Phone: [phone]
Website: emcsolutions-com
Eco Sa e Lighting
4600 NW Camas Meadows Drive,
Suite 210
Camas, WA
Phone: [phone]
Website: http://www.est
lights.com/about-us/
or ryhn E uipment Company
3711 E. NewbySt.
Nampa, D
Phone: [phone]
Website: norbryhn.com
J ssociates, PLLC
1152-ondAve
ReLburg, tD
Phone: [phone]
Valley lmplement
2570 N Main
Logan, UT
Phone: [phone]
Website: valley-implement.com
Total Energy Electrical Full
Spectrum Ser ices
121 E.38th, X06
,oise, iD
Phone.[phone]
Website: www.fu llspecservices.com
Electrical holesale Supply Go., lnc.
Corporate
1355 Fremont Ave
daho Falls, llD
Phone: [phone]
Website: www. ews@inc.@m
atest
2324 amy street
fostercity, CA
Phone: [phone] :3434
Specialties
Lighting
Specialties
Laghting
Specialties
Controls
HVAC - unitary
Motors and VFDs
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDS
Specialties
HVAC - unitaryMotors and VFDS
Specialties
Lighting
Business Type
Conaactor
Business Type
Distributor
Manufacturer - Rep
Business Type
Contractor
Manufiacturer - Rep
Business Type
Contractor
Distributor
Manufacturer - Rep
Business Type
Distributor
Business Type
Distributor
Join Date
04t0'U2009
Join Date
04t01t2007
Join Date
06101t2007
Join Date
05/01/2006
Join Date
05t01t2004
Join Date
02t11t2013
Join Date
ost01t2012
Join Date
10t21t2013
Join Date
12t05t2012
Join Date
10t11t2012
Join Date
09DA2U2
Join Date
04t02t2013
Projects
Completed
8
Proiects
Completed
22
Projecb
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Gompleted
Projects
Completed
Projects
Completed
null
Projects
Completed
null
Projects
Completed
null
Projects
Completed
22
Specialties
HVAC - unitary
Motors and VFDs
Specialties
luilding envelope
Specialties
Controls
Farm and Dairy
Iftigation
Motors and VFDs
Specialties
Lighting
Business Type
Distributor
Business Type
Architect
Business Type
Contractor
Business Type
Contractor
Specialties
Controls
Lighting
Motors and VFDs
Specialties
Appliances
Business Type
Diskibutor
Business Type
Architect
I :m ! oc J aountaih PoJei . didsion o?aciJCorp and p.tr oilt id Lmcilc.n En.rgy :roldlng. Comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 492 of 495
Energy Eniciency Illiance
Witness: Kathryn C. Hymas
ROCKY MOUNTAINpo$/ER
Coolerado Corporation
4700 W. 60th Ave., Ste. 3
Arvada, CO
Phone: [phone]
Website: coolerado.com
aintenance Engineering, Ltd.
P.O. ..o:2123
Fargo, ND
Phone: [phone]
Website: www.me-dtc.com
Compressor . Pump i... Ser ice, lnc.
3333 W. 2400 S.
Salt Lake City, UT
Phone: [phone]
Website: www.compressor-pump.com
L S Lighting aintenance Ser ice
663 West 4330 South
Salt Lake City, UT
Phone: [phone]
Website: lmslighting.com
. es LED Technologies, LLC.
1'1811 North Freeway, Suite 181
Houston, T-
Phone: [phone]
Website: www.wesled.com
idgley u er, lnc.
2465 Progress Drive
Salt Lake City, UT
Phone: [phone]
Website: Migley-huber.com
eal reen LED
4280 W. 200 N.
Cedar City, UT
Phone: [phone]
Website: www. realgreen.net
Petroleum E uipment Co
1 174 So. 300 W
Salt Lake City, UTPhone:801-487-8276
Website: www. petro-equip. net
et or Consulting Ser..ices, inc.
563 West 500 South
Suite 245,
i,ountiful, UT
Phone: [phone]
Website: http://www. ncsi. us
oyal holesale Electric Logan
917 W600 N Ste 101
Logan, UT
Phone: [phone]
Website: royalutah.com
spen Engineering andEn ironmental LLC
140 Aspen Circle
Park City, UT
Phone: [phone]
Website: www. a2e-llc. com
Specialties
HVAC - evaporative
HVAC - unitary
Specialties
Lighting
Specialties
Compressed Air
Specialties
Controls
Lighting
Motors and VFDS
Specialties
Lighting
Specialties
HVAC - evaporative
HVAC - unitary
Specialties
Lighting
Specialties
Lighting
Specialties
Office Equipment
Specialties
Lighting
Specialties
truilding envelope
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDs
Business Type
Distributor
Manufacturer - Rep
Business Type
Other: Manufacturer
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Manufacturer - Rep
Business Type
Distributor
Business Type
Distributor
Business Type
Architec{
Contractor
Engineering Firm
Manufacturer - Rep
Business Type
Distributor
Business Type
Engineering Firm
Join Date
03t0'U2007
Join Date
10t05t2012
Join Date
10t2112013
Join Date
10to2t2002
Join Date
07to1t2011
Join Date
05t01t2007
Join Date
09t01t2012
Join Date
10t03t2013
Join Date
04t29t2013
Join Date
01to9t2008
Join Date
03t1812013
Projects
Gompleted
Projects
Completed
null
Projects
Completed
Projects
ugmcteteo
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
12
Proiects
Completed
rtmlocaliountainPo:er,adiJsionolacltorp andpanoEFldlmcrlc.nEncrgyrtoldingrCompany
Rocky Mountain Power
Exhibit No. 1 Page 493 of 495
Energy Elficiency tr lliance
Witness: Kathryn C. Hymas
VROCKY MOUNTAIN
XPowER
Van Boerum Fran ssociates
330 South 300 East
Salt Lake City, UT
Phone: [phone]
Website: www.vbfa.com
Engineering Economics, lnc.
780 Simms Street Suite 210
Golden, CO
Phone: [phone]
Consolidated Electrical Distri utors
Specialties
ruilding envelope
Controls
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDS
Specialties
tuilding envelope
Controls
HVAC - evaporative
HVAC - unitary
Specialties
Lighting
Business Type
Architect
Engineering Firm
Other
Business Type
Engrneenng Frrm
Business Type
Distributor
Business Type
Distributor
Manufacturer - Rep
Business Type
Distribuior
Manufacturer - Rep
Business Type
Engineenng Firm
Business Type
Distributor
ldaho Falls
865 Pancheri
daho Falls, ID
Phone:[phone]
,anitaTe rindoi. Film
4010 La Reunion Pkwy, [100
Dallas, TLI
Phone: [phone]
Website: www. HanitaTek.com
ESL Vision LLC
P.O. !o-58565
Salt Lake City, UT
Phone: [phone]
Website: www.eslvision.com
Engineered Systems rssoc., lnc.
1355 E. Center Street
Pocatello, LID
Phone: [phone]
Electrical holesale Supply Co..
Pocatello
220 West Maple
Pocatello, tD
Phone: 208-233- l 362
Website: www.ewscoinc.com
Specialties
nuilding envelope
Specialties
Controls
Lighting
Specialties
Controls
HVAC - evaporative
HVAC - unitary
Motors and VFDS
lnc. Specialties
Controls
Lighting
Motors and VFDs
Join Date
01t01t2012
Join Date
01t2012014
Join Date
o9t24t2012
Join Date
09/09/201 3
Join Date
o1t13t2013
Join Date
01t10t2014
Join Date
09t22t2012
Join Date
o9122t2012
Join Date
02t01t2009
Projects
Completed
Projects
Completed
Proiects
Completeda
Projects
Completed
Projects
Completed
Projects
Completed
Projects
Completed
null
Electrical ' holesale Supply Co., lnc. Specialtiesldaho Falls Libhting
Business Type
Distributor
Business Type
Contractor
Business Type
Distributor
Business Type
Distributor
Projects
Completed
133140 McNeil Dr.
daho Falls, r,D
Phone: [phone]
Website: [e-mail]
S y ie Electric lnc
2299 W Omni Dr
daho Falls, O
Phone: [phone]
llredls lncorporated
442 North 1000 West Unit i r104
Logan, UT
Phone: [phone]
Website: www.allreds.net
Electrical holesale Supply Co., lnc.Driggs
83C Rocky Road nd Lp.
Driggs, :D
Phone: [phone]
Website: www.ewscoinc.com
Specialties
Lighting
Specialties
HVAC - unitary
Specialties
Controls
Lighting
Motors and VFDS
Proiects
Completed
Join Date Projects05l11nol Completed
Join Date Projects0912212012 Completed
7
f, :m loca, f ountain PoJer, a diDsion o?aciocorp end p.d oot ld t m..ican Encrgy foldlngr comp.ny
Rocky Mountain Power
Exhibit No. 1 Page 494 of495
Energy EUficiency Illiance
Witness: Kathryn C. Hymas
Uf ROCKY MOUNTAIN'tPowER
ountain 'est echanical
2336 W. 5200 S.
ReLburg, lD
Phone: [phone]
Website:
www. mountainwestmechanical. com
tah amas Controls lnc.
1 3526 S. 1 10 W.
Draper, UT
Phone: [phone]
Website: www. utahyamas.com
ll :...merican Lighting lnc.
P.O. 1.1o,f2996
rdaho Falls, D
Phone:[phone]
usta e .LarsonCompany
1395 Northgate Mile
.daho Falls, 0Phone.[phone]
Website: galarson.com
Electrical E uipment Company
540 W. 20th st.
-daho Falls. DPhone:208-5224732
Website: electricalequipment. com
D Supply Facilities aintenance,
Ltd.
10641 Scripps Summit Court
San Diego, CA
Phone: [phone]
Website: www. hdsupplysolutions.com
Larsen Electric, LLC
P.a. =-toa2871
Pocatello. rD
Phone: [phone]
Clar s uality oo ing, lnc.
334 W. Anderson Avenue
Salt Lake City, UT
Phone:80'l-266-3575
Website: clarkroof.com
Pete s Lighting
227 S. ohnson Ave.
Pocatello. tlD
Phone: [phone]
Energy lndustries
425 W. Pueblo St
oise, iD
Phone: [phone]
Website: energy-industries. com
Si a Sarna it lncorporated
2881 South 900 West
Salt Lake City, UT
Phone: [phone]
Website: usa.sarnafi l.sika.com
Trane
2817 S. 1030 W
Salt Lake City, UT
Phone: 80'1 -486-0500
Website: www.trane.com
Specialties
uilding envelope
Controls
HVAC - evaporative
HVAC - unitary
Lighting
Motors and VFDS
Other: Other Specialty
Specialties
Lighting
Specialties
HVAC - unitary
Motors and VFDs
Specialties
Lighting
Other: Other Specialty
Specialties
Appliances
HVAC - evaporative
HVAC - unitary
Specialties
Lighting
Specialtiesiuilding envelope
Specialties
Lighting
Specialties
Lighting
Specialtieslluilding envelope
Business Type
Contractor
Distributor
Engrneering Firm
Manufacturer - Rep
Business Type
Distributor
Business Type
Distributor
Business Type
Contrador
Business Type
Distributor
Business Type
Contractor
Business Type
Contractor
Business Type
Distributor
Business Type
Other
Business Type
Contraclor
Specialties
HVAC - evaporative
HVAC - unitary
Business TypeContractor Join Date
03t17t2014
Join Date
01t21t2013
Join Date
03t01t2010
Join Date
09to1t2008
Join Date
01t0'U2012
Join Date
01t22t2014
Join Date
0912212012
Join Date
09119t2012
Join Date
09/01/2010
Join Date
05/30/2006
Join Date
11tO1t201'l
Join Date
03/0 1 /2005
Projects
Gompleted
Projects
Gompleted
Projects
Completed
1
Projects
Completed
Projecb
Completed
1
Projects
Completed
Specialties
Controls
HVAC - unitary
Motors and VFDS
Business Type
Distributor
Manufacturer - Rep
Proiects
Completed
1
Projects
Completed
null
Projects
Completed
1
Prolects
Completed
2
Projects
Completed
Projects
Completed
L:Uloc:y !ountain Poler, a dillion oPac,rcorp .nd p.frolid:m.ricrn Encrgy Uoldingr Company
Rocky Mountain Power
Exhibit No. 1 Page 495 of 495
Energy Emiciency Illiance
Wtness: Kathryn C. Hymas
VROCKY MO.JNTAIN-{nowsn
c rinstry Essention, LLC
112 N. Rubey Dr.
Suite 200,
Golden, CO
Phone: [phone]
Website: www. mckinstry.com
reen Creati e LLC
533 Airport l]lvd., Suite 212
L=urlingame, CA
Phone: [phone]
Website: www. gc-lighting.com
LED lndustries lnc
3001 N. US Highway12
Spring Grove, O
Phone: 80'l-801-5969
D S Electrical
363 West Chubbuck Road
Chubbuck, tD
Phone: 208-73'1 -370 1
. arris -.echanical lntermountain
'1925 South Milestone Drive
Suite E,
Salt Lake City, UT
Phone: [phone]
Website: www.hmcc.com
Specialties
truilding envelope
Compressed Air
Controls
HVAC - evaporative
HVAC - unitary
arigation
Lighting
Motors and VFDs
Other: Other Specialty
Specialties
Lighting
Business Type
Engineering Firm
Business Type
Manufacturer - Rep
Join Date
02t12t2014
Join Date
06t25t2013
Join Date
12t18t2013
Join Date
12t01t2008
Join Dateun7no14
Projects
Completed
Projects
Gompleted
Specialties
Lighting
Specialties
Lighting
Motors and VFDS
Specialties
HVAC - evaporative
HVAC - unitary
Business Type
Manufacturer - Rep
Business Type
Distributor
Business Type
Contractor
Projects
Completed
Projects
Completed
36
Projects
Gompleted
trroloc!y Lountiin Ponlr, a dlD!ion oPaclmorp .nd p.fr oiloidEm.ilc.n En.rgy foldlngt ComP.ny
nFeFt\rr {i
caseNo. PACEli4tUh -?
frHilliliu*,qmry*;
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Kathryn C. Hymas
July 2014
Rocky Mountain Power
Exhibit No.2 Page 1 of 4
Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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Rocky Mountain Power
Exhibit No. 2 Page 2 ot 4
Case No. PAC-E-14-07
\Mtness: Kathryn C. Hymas
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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Exhibit No. 2 Page 4 of 4
Case No. PAC-E-14-07
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
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Case No. PAC-E-14-07
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ROCKY MOUNTAIN POWER
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Exhibit No. 4 Page 1 of 4
Case No. PAC-E-14-O7
Witness: Kathryn C. Hymas
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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Case No. PAC-E-14-07
Witness: Kathryn C. Hymas
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