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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION FOR APPROVAL
OF CHANGES TO THE IRRIGATION
PEAK REWARDS PROGRA.
CASE NO. IPC-E-10-46
I DAHO POWER COMPANY
DIRECT TESTIMONY
OF
PETER PENGILLY
1 Q.Please state your name, address, and present
2 occupation.
3 A.My name is Peter Pengilly. My business
4 address is 1221 West Idaho Street, Boise, Idaho.
5 Q.By whom are you employed and in what
6 capacity?
7 A.I am employed by Idaho Power Company (~Idaho
8 Power" or ~Company") as a Customer Research and Analysis
9 Leader in its Customer Relations and Energy Efficiency
10 group.
11 Q.Please describe your educational background.
12 A.In May of 1976, I received a Bachelor of
13 Science Degree in Anthropology from University of Idaho,
14 Moscow, Idaho. In 1986, I began attending Boise State
15 University, and in 1992, I received a Bachelor of Science
16 Degree in Mathematics. I continued at Boise State
17 Uni versi ty after graduation as an adj unct professor in
18 mathematics while completing courses specializing in
19 statistics.
20 I have since attended numerous seminars and
21 conferences on statistical analysis and on pricing issues
22 related to the utility industry and have attended seminars
23 and courses involving public utility regulation. These
24 courses include Edison Electric Institute' s (~EEI")
PENGILLY, DI 1
Idaho Power Company
1 Advanced Rate Course and New Mexico State University's
2 Center for Public Utili ties Rates Course and The
3 Restructuring Electric Industry Course . Additionally, I
4 have attended numerous conferences and forums on energy
5 efficiency and demand response, including the Demand
6 Response Coordinating Committee (~DRCC") meetings, the E-
7 Source Forum, and Bonneville Power Administration post-2011
8 energy efficiency meeting.
9 Q.Please describe your work experience.
10 A.From 1976 until 1986, I worked as an
11 archaeological technician on contract with various
12 uni versi ties, government agencies, and private contractors.
13 At the same time, I was involved in managing a small
14 family-owned business. From 1986 until 1992, I was
15 employed by the Idaho State Historical Society managing
16 their Archaeology laboratory. In 1992, I went to work as a
17 Research Analyst for the Idaho Department of Correction.
18 In 1993, I transferred to the Idaho Department of Labor as
19 a Research Analyst Supervisor under the auspices of the
20 Bureau of Labor Statistics. This position included
21 supervising a staff as well as performing a variety of
22 economic and statistical analyses and reporting. I was
23 employed by Idaho Power Company in December of 1999 as a
24 Senior Pricing Analyst in the Pricing and Regulatory
PENGILLY, DI 2
Idaho Power Company
1 Services Department. My duties as a Senior Pricing Analyst
2 included the development of alternative pricing structures,
3 management of pricing programs, the analysis of the impact
4 on customers of rate design changes, and the administration
5 of the Company's tariffs.In that position I helped
6 develop several demand response programs, a time-of-use
7 pilot program, and a critical peak pricing program.
8 In 2006, I was promoted to my current position as
9 Customer Research and Analysis Leader in the Customer
10 Relations and Energy Efficiency Department. In this
11 position I am responsible for the research, analysis,
12 forecasting, and reporting associated with Idaho Power's
13 energy efficiency and demand response programs. As such, I
14 am a member of the Northwest Energy Efficiency Alliance
15 (~NEEA") cost-effectiveness expert committee, a
16 representative at the Pacific Northwest Demand Response
17 Project (~PNDRP"), Idaho Power's representative at the
18 Regional Technical Forum (~RTF"), and a member of the E-
19 Source DSM Executive Council.
20 Q.What is the scope of your testimony in this
21 proceeding?
22 A.My testimony will discuss the Company's
23 recent review of the effective integration of demand
24 response into Idaho Power's electrical system. Further, my
PENGILLY, DI 3
Idaho Power Company
1 testimony will describe a number of proposed modifications
2 to the Irrigation Peak Rewards Program (Program), Schedule
3 23, which are based upon the findings of the review.
4 CURNT PROGRA OVERVIEW
5 Q.Please provide an overview of the current
6 Irrigation Peak Rewards Program.
7 A.The Irrigation Peak Rewards Program,
8 Schedule 23 is a voluntary load control program currently
9 available to agricultural irrigation customers. The purpose
10 of the Program is to reduce the Company's system summer
11 peak loads. If not for the Program, growing summer peak
12 loads would likely require the construction of additional
13 simple cycle gas peaker capacity to meet system peak a few
14 hours each year.
15 Under the Program, the Company turns off all
16 irrigation pumps behind a participating metered service
17 point during the summer, Monday through Saturday, with the
18 use of an electric switch or a switch that is communicated
19 with via cell phone or power-line carrier technology via
20 Idaho Power's Automated Meter Infrastructure (~AMI")
21 system. Customers who have irrigation service usage greater
22 than 1, 000 cumulative horsepower (~hp") have the option to
23 manually interrupt electric service to their irrigation
24 pumps. In exchange for allowing the Company to turn their
PENGILLY, DI 4
Idaho Power Company
1 pumps off, participating Customers receive a monthly
2 monetary incentive during the Program period.
3 Load reduction is achieved by turning off specified
4 irrigation pumps for up to 4 hours per day, for up to 15
5 hours per week, and for up to 60 hours per Program Season.
6 The Program operates during the Company's typical peak
7 season of June 15th through August 15 (Program Season) .
8 Q.In the past has Idaho Power's Irrigation
9 Peak Rewards Program achieved its targets?
10 A.Yes. Each year the Program has met or
11 exceeded the targets set for participation and megawatt
12 (~MW") reduction.
13 Q.Does the Company conduct an annual review of
14 the Program to analyze the effectiveness of Program
15 provisions?
16 A.Yes. Each year the Company evaluates the
17 operations of the Program to ensure that the Program design
18 is cost-effective. The annual review process also includes
19 an evaluation of other programmatic aspects such as
20 operational efficiency and customer satisfaction. These
21 findings are reported in the Demand-Side Management Annual
22 Report filed with the Commission on March 15 of each year.
PENGILLY, DI 5
Idaho Power Company
1 PROGRA REVIEW 2010
2 Q.How has this year's Program review differed
3 from reviews performed in prior years?
4 A.In 2010, the Company enhanced its
5 traditional annual review by conducting an additional study
6 in conjunction with its 2011 Integrated Resource Plan
7 (~IRP") analysis. This study was conducted in an effort to
8 ensure that Program design is aligned with the resource
9 needs identified by the IRP. The primary obj ecti ves of this
10 effort were to:(1) leverage the IRP analysis to determine
11 the Company's future capacity needs that can be cost-
12 effectively met with demand response and (2) design and
13 operate demand response programs in a manner that satisfies
14 the identified resource need. The proposed Program
15 modifications are a direct result of that review.
16 Q.Are you sponsoring any exhibits as part of
17 your testimony?
18 A.Yes . Exhibit No. 1 contains slides presented
19 at the November 18, 2010, Integrated Resource Plan Advisory
20 Council (IRPAC) meeting. Exhibit No.2 details the
21 proposed incentive payment structure and provides examples
22 of incentive payments at different hours of operation.
23 Q.Please describe the 2010 Program review.
PENGILLY, DI 6
Idaho Power Company
1 A.The first part of the review involved an
2 analysis of the impact that the Company's demand response
3 programs had on the Company's peak-day load shape in 2010.
4 The results of this analysis are detailed on page 1 of
5 Exhibit No.1. As can be seen on page 1 of Exhibit No.1,
6 the Company's demand response programs clearly had an
7 effect on the peak-day loads. However, it can also be seen
8 that the Company's resulting peak demand occurred after
9 8: 00 p. m., after the demand response program operational
10 period of 1:00 p.m. to 8:00 p.m. In addition, the peak
11 demand that occurred at 9:00 p.m. was at a level much
12 greater than demand during the demand response program
13 operational period, thereby creating a ~trough effect" in
14 the load shape.
15 Ideally, demand response would flatten the peak-day
16 load shapes as shown on page 2 of Exhibit No.1. A flat
17 load shape during the demand response program operational
18 period would indicate that 100 percent of the demand
19 reduction provided by the programs is avoiding the need for
20 capacity rather than something less than 100 percent that
21 would exist under the ~trough effect." In other words, a
22 ~trough" in the peak-day load shape suggests that the
23 demand reduction was not optimally aligned with the load
24 conditions.
PENGILLY, DI 7
Idaho Power Company
1 The second part of the review centered around the
2 Company's IRP process with input from representatives from
3 Idaho Power's demand response program managers and
4 planners, generation dispatch, power supply planning, and
5 transmission planning. The Company began by analyzing the
6 load duration curves for the year's forecast in the 2011
7 IRP process to determine a maximum potential level of
8 demand reduction that could be expected from a resource
9 that is available 60 hours per year. Sixty hours is the
10 Program's maximum hours of load control. The results of
11 the load duration analysis can be seen on page 3 of Exhibit
12 No.1. The Company then leveraged its 2011 IRP analysis to
13 determine its proj ected demand response resource need over
14 the planning period under extreme load conditions.
15 The results from the resource need analysis and the
16 analysis of demand reduction potential were then analyzed
17 together, as shown on page 4 of Exhibit No.1, to determine
18 the appropriate level of demand response to pursue through
19 Idaho Power's programs.
20 Q.Please describe page 4 of Exhibit No.1.
21 A.Page 4 of Exhibit No. 1 provides a schedule
22 of the appropriate level of demand response to be pursued
23 by the Company through its demand response programs. Column
24 F of the schedule details the annual demand response needed
PENGILLY, DI 8
Idaho Power Company
lover the next five years according to a resource adequacy
2 analysis. A resource adequacy analysis compares the
3 Company's existing and committed resource capacity
4 resul ting from its most recent IRP analysis, in this case
5 the 2011 IRP, against the amount of forecasted annual peak-
6 hour demand under 95th percentile (extreme load conditions)
7 to determine future capacity need. This approach applied a
8 methodology and utilized inputs consistent with the
9 Company's 2011 IRP analysis. Column G of the schedule
10 details the level of demand response resource potential
11 identified by a load duration curve analysis. Column H of
12 the schedule provides the estimated amount of demand
13 response that should be pursued by the Company by
14 identifying the lesser of the resource need in Column F and
15 the demand response potential in Column G. According to
16 the results in Column H, under 95th percentile load
17 conditions, the Company's annual capacity need is expected
18 to vary from a minimum of 155 MW to a maximum of 322 MW in
19 the next five years, a difference of over 50 percent.
20 Q.What conclusions has the Company reached
21 following its review of the information provided on Exhibit
22 No.1?
23 A.After a thorough review of the information
24 contained on Exhibit No. 1 and after extensive
PENGILLY, DI 9
Idaho Power Company
1 interdepartmental discussion, the Company has concluded
2 that its need for demand response extends beyond 8: 00 p. m.
3 to at least 9: 00 p. m. Further, the Company has concluded
4 that its annual capacity need during the highest 60 hours
S of demand is expected to vary by over SO percent during the
6 next five years.
7 Q.How did these findings and conclusions help
8 shape the proposed Program modifications?
9 A.Based upon the findings and conclusions reached by the
10 Company in its 2010 Program review and analyses, a number
11 of potential Program modifications were indentified.
12 First, in response to the need for load reduction until
13 9:00 p.m., the Company explored methods by which it could
14 extend the interruption period for a subset of
lS participants. Second, based upon the anticipated annual
16 variations in capacity needed, the Company explored a
17 number of methods to better align annual Program costs with
18 the annual capacity need. Specifically, the Company
19 explored modifications to the Program's incentive cost
20 structure that would move from the current 100 percent
21 fixed structure to a cost structure that would allow for
22 some portion of the costs to vary in proportion to the
23 projected capacity need.
PENGILLY, DI 10
Idaho Power Company
1 PROPOSED PROGRA CHAGES
2 Q.Please describe the proposed Program
3 modifications.
4 A.The Company is proposing the following
5 Program modifications:
6 1.Include the 8:00 p.m. to 9:00 p.m.
7 Mountain Daylight Time (~MDT") hour as an ~Extended
8 Interruption" option on a voluntary basis;
9 2.Change the incentive cost structure for
10 the Program from a fixed payment methodology to a
11 methodology that combines a fixed and variable incentive
12 payment. The proposed incentive structure pays
13 participants a portion of their total incentive for
14 participation alone (fixed) and a portion based on how much
15 the Company utilizes the Program (variable);
16 3.Include one Program test event per
17 Program Season not subj ect to a variable payment;
18 4.Modify the requirements under the
19 Program's Dispatchable Option 3 to align with the proposed
20 incentive structure; and
21 5.Modify the opt-out penalty for the
22 Program.
PENGILLY, DIll
Idaho Power Company
1 Q.Did the Company develop the proposed changes
2 to the Program with input from other interested parties
3 external to Idaho Power?
4 A.Yes. The Company met separately with
5 representatives of the Idaho Irrigation Pumpers Association
6 (~IIPA") and the Commission Staff to inform them of the
7 findings from the Company's recent resource planning
8 analyses and to seek input regarding potential Program
9 modifications supported by those analyses. On November 4,
10 2010, Company representatives met at its Mini-Cassia office
11 in Heyburn, Idaho with representatives of the IIPA.
12 Subsequently, Company representatives met with Commission
13 Staff on November 9, 2010, and again with representatives
14 of the IIPA on December 2, 2010.
15 The results of the 2010 analysis and general Program
16 changes were also presented at the October 26 meeting of
17 the Energy Efficiency Advisory Committee (~EEAG") and the
18 November 18 meeting of the IRPAC.
19 Q.Did the Company receive input from the IIPA
20 or the Commission Staff that was ultimately included in the
21 proposed Program modifications?
22 A.Yes. At IIPA's suggestion, the Company is
23 proposing to pay a higher ~Extended Interruption" Variable
24 Energy Credit incentive payment to customers selecting to
PENGILLY, DI 12
Idaho Power Company
1 participate from 8:00 p.m. to 9:00 p.m. MDT. In working
2 with the IIPA, it was noted that it can be a hardship for
3 some customers to get systems restarted before nightfall.
4 Therefore, the Company is recommending that this ~Extended
5 Hours" option be offered on a voluntary basis rather than a
6 requirement for all customers. Under this option,
7 Customers who are willing to accept an extended
8 interruption period will receive a higher incentive payment
9 for event hours.
10 Q.Do you expect this modification to improve
11 the effectiveness of the Program?
12 A.Yes. As discussed earlier in my testimony,
13 the Company experienced substantial loads on or about the
14 8: 00 p.m. MDT hour during interruption days when Program
15 participants resumed their energy consumption. Customers
16 will benefit by having the Company extend the time period
17 to 9: 00 p.m. MDT in order to reduce the peak at this hour.
18 This modification will provide a better opportunity to
19 fully utilize the full value of the Program by reducing
20 loads across the entire peak period.
21 Q.Please describe the proposed incentive
22 payment structure.
23 A.The proposed incentive payment structure for
24 Dispatchable Interruption Options 1, 2, and 3 will include
PENGILLY, DI 13
Idaho Power Company
1 a variable incentive payment in addition to the current
2 fixed incentive payment. The variable portion of the
3 incenti ve will represent approximately 60 percent of the
4 total incentive amount for an average participant and be
5 based on the number of interruption hours multiplied by the
6 amount of monthly billing demand measured in kilowatts
7 (~kW"). Currently, the incentive payment structure is a
8 fixed amount that only varies based on the customer's
9 monthly billing demand and energy usage; it does not vary
10 based on the number of interruption hours (i. e., use of the
11 Program). Overall, the proposed changes result in a larger
12 incenti ve payment, as compared to what participants
13 currently receive, if the Program is dispatched at the
14 maximum of 60 hours per Program Season. The Company is not
15 proposing any changes to the incentive structure for the
16 Timer Option.
17 Q.How does the modified incentive structure
18 for the Dispatchable Interruption Options address the
19 Company's concerns regarding the projected variations in
20 capacity need over the coming years?
21 A.The Company believes that having a portion
22 of the incentive based on the actual utilization of the
23 resource more closely aligns the cost of demand response
24 with the variable capacity needed. The summers of 2009 and
PENGILLY, DI 14
Idaho Power Company
1 2010 were good examples of how weather and load variation
2 can create a situation where demand response resources are
3 not as critical to the system.
4 Q.What specific incentive changes are being
5 proposed by the Company in this filing?
6 A.For the Timer Option, the incentives will
7 not change. For Dispatchable Options 1, 2, and 3, the
8 participants will be paid a fixed Demand Credit of $5.00
9 per kW and an Energy Credit of $0.0038 per billed kWh. The
10 variable portion of the incentive will be $0.35 per kWh
11 calculated as the Billing Demand multiplied by the
12 interruption hours of the Program. Participants willing to
13 reduce demand in the 8:00 p.m. to 9:00 p.m. hour will
14 receive a variable incentive payment of $0.40 per kWh,
15 calculated as the Billing Demand, multiplied by the
16 interruption hours of the Program. Exhibit No. 2 details
17 the incentives and provides examples of the incentive
18 payments at different hours of interruption.
19 Q.Can you further describe Exhibit No.2?
20 A.Exhibit No. 2 includes a table that
21 illustrates the impact of the modified incentive payment
22 structure based on a hypothetical participant with a 125
23 horsepower pump. The table provides the individual payment
24 components based on a 40 percent fixed and 60 percent
PENGILLY, DI 15
Idaho Power Company
1 variable incentive payment structure. The table compares
2 the current incentive payment structure to the proposed
3 incenti ve payment structure. The fixed energy (kWh)
4 incentive is based on an average participant's usage over
S the eight-week Program period. The variable kWh incentive
6 is determined by multiplying the kW demand by the number of
7 event hours. The table illustrates that if the Company has
8 no demand response events, it will pay 40 percent of the
9 current incentive; the Company will pay 106 percent of the
10 current incentive if the Program is fully utilized at 60
11 hours.
12 Q.What is the basis for the proposed 40
13 percent fixed and 60 percent variable incentive payment
14 structure?
lS A.As discussed earlier in my testimony, the
16 Company estimates that the annual need for demand response
17 resources under extreme conditions (9Sth percentile) will
18 vary in the next five years by more than SO percent. If
19 the Company were to limit annual Program participation to
20 match the annual capacity need, it could potentially reduce
21 its incentive costs by over SO percent in at least one of
22 those years. However, because varying Program
23 participation could have unwanted impacts to customer
24 satisfaction and ultimately long-term participation levels,
PENGILLY, DI 16
Idaho Power Company
1 the Company opted to move to the proposed variable payment
2 structure. The Company believes that the 60 percent
3 variable payment structure is reflective of the variations
4 in cost that would exist under a variable participation
5 approach. Furthermore, the Company anticipates that the
6 proposed level of fixed incentive will be adequate to
7 retain current participants.
8 Q.Why is the Company proposing that one
9 dispatched test event each year not receive a variable
10 incentive payment but rather be paid entirely with a fixed
11 payment?
12 A.It is possible that the Company may not have
13 a need for load control events in a particular summer. By
14 dispatching at least one event per Program Season, the
15 Company can test Program equipment and communication
16 channels to ensure that the load reduction is available
17 when needed. Having at least one event per Program Season
18 will also keep participants familiar with the Program and
19 help them manage their Program expectations. A single test
20 event that is incentivized by a fixed payment also removes
21 any disincentive for Idaho Power to use this event.
22 Q.What additional requirements is the Company
23 proposing for Dispatchable Option 3?
PENGILLY, DI 17
Idaho Power Company
1 A.The Company is proposing the following
2 modifications to Dispatchable Option 3:(1) to require
3 participants to nominate their load reduction, (2) to
4 change the opt-out policy, and (3) to change the baseline
5 from which participants' load reduction is calculated.
6 Q.Why is the Company proposing that
7 Dispatchable Option 3 participants nominate the amount of
8 load reduction they can provide?
9 A.Currently under Dispatchable Option 3,
10 participants have the option to provide any portion of
11 their load during a load control event. Under the current
12 incentive structure, a participant could be paid a larger
13 incentive if no events were called. This has not been a
14 significant issue in the past because normally the Company
15 has called at least one event per Billing Period.
16 Under the Company's proposed changes to Dispatchable
17 Option 3, participant's fixed incentive payment will be
18 calculated based on the nominated load reduction and energy
19 use if no load control events are dispatched. This will
20 reduce the chance of the Company overpaying participants if
21 no load control events are dispatched.
22 Q.Please describe the current opt-out penalty
23 under the Dispatchable Interruption Options.
PENGILLY, DI 18
Idaho Power Company
1 A.Currently, the opt-out penalty is $0. OOS per
2 monthly billed kWh per opt-out occurrence for customers
3 selecting the Dispatchable Interruption Options 1 and 2
4 under the Program. Currently, Dispatchable Option 3
S participants do not pay an opt-out penalty.
6 Q.Please describe the proposed opt-out penalty
7 under the Dispatchable Interruption Options.
8 A.The Company is proposing a $1.00 per kW opt-
9 out penalty for all Dispatchable Interruption Options.
10 Q.Why is the Company proposing a change in the
11 opt-out penalty?
12 A.First, the $ 1.00 per kW will make it easier
13 for customers to estimate what an opt-out is going to cost
14 ahead of time, which could influence their decision to opt-
lS out. Second, it is now imperative that Dispatchable Option
16 3 participants be subject to the opt-out penalty. For
17 example, under the current Program provisions, if a
18 Dispatchable Option 3 participant has nominated the full
19 load of a pump station, then their fixed portion of the
20 payment would be based on that amount. During events when
21 the customer chose not to turn the whole pumping station
22 off, the Program would pay the fixed portion on potential
23 load reduction the Company would not be receiving. If they
24 did not provide the full amount of nominated kW, the
PENGILLY, DI 19
Idaho Power Company
1 penalty would apply to the difference between what they
2 provided and what they nominated.
3 Addi tionally, Dispatchable Option 3 participants are
4 not restricted to five opt-outs per season as are
5 Dispatchable Options 1 and 2 participants. Under the
6 proposed changes, if Idaho Power fully utilized the Program
7 for the maximum 60 hours during the Program Season, and if
8 the Participant did not provide the entire nominated kW
9 more than five times, then the penalty would never exceed
10 100 percent of the credit. This will encourage
11 Dispatchable Option 3 participants to provide at least the
12 kW amount nominated.
13 Q.How is the load reduction for participants
14 under Dispatchable Option 3 determined?
15 A.To be eligible to participate in
16 Dispatchable Option 3, participants must have interval
17 meters installed at their Metered Service Points. Idaho
18 Power analyzes this meter data after an event and
19 determines the amount of load reduction by subtracting the
20 actual demand from a baseline demand (Program kW) .
21 Q.How is the current baseline for load
22 reduction Program kW determined for Dispatchable Option 3
23 participants?
PENGILLY, DI 20
Idaho Power Company
1 A.The current Program kW for Dispatchable
2 Option 3 participants is the maximum demand in the 24 hours
3 prior to an event.
4 Q.What change is the Company proposing for the
5 calculation of the baseline Program kW under Dispatchable
6 Option 3?
7 A.The Company is proposing to calculate the
8 Program kW based upon the average demand between the 10: 00
9 p.m. and 11:00 a.m. MDT immediately prior to an event, as
10 measured in kW over the load profile metering intervals,
11 during each load control event initiated during a Billing
12 Period.
13 Q.Why is the Company proposing a change to
14 this baseline calculation?
15 A.In the past, there were a few instances
16 where a high demand was registered prior to the event for a
17 short duration and did not accurately represent the
18 customer's load prior to an event. By changing the
19 calculation of Program kW for Dispatchable Option 3
20 participants, it will more accurately represent the load
21 reduction provided by the customer and minimize the risk of
22 paying the customer for demand reduction that the Company
23 did not actually receive.
PENGILLY, DI 21
Idaho Power Company
1 COST-EFFECTIVENESS
2 Q.Has the Company performed an analysis to
3 determine that the proposed Program design is cost
4 effective?
S A.Yes. The benefit/cost (B/C) analysis for
6 the Irrigation Peak Rewards Program is based on a 20-year
7 model that uses financial and Demand-Side Management
8 al ternati ve costs assumptions from the IRP. As published
9 in the 2009 IRP, for peaking alternatives such as demand
10 response programs, a 162 MW simple-cycle combustion turbine
11 is used as a cost basis. Idaho Power' s cost-effectiveness
12 model representing the Program over a 20-year period is
13 updated annually with actual benefits and costs. The model
14 is currently updated through 2009 and will be updated with
lS 2010 actual expenses and benefits after the 2010 financial
16 books are closed and reported.
17 Q.Considering the proposed changes, is the
18 Program still cost-effective?
19 A.Yes. The current Program's B/C ratio as
20 reported in the Demand-Side Management 2009 Annual Report
21 was 1. SO over a 20-year planning period. When considering
22 the proposed Program changes, several assumptions were
23 changed for the Program in future years. Participation was
24 assumed to remain fairly constant through the planning
PENGILLY, DI 22
Idaho Power Company
1 period. Because of the proposed variable pricing, the
2 incentives were analyzed based on zero dispatched load
3 control events, with three dispatched events, with seven
4 dispatched events, and at full utilization of the Program
5 with 15 dispatched events. Under all scenarios, the B/C
6 ratios are greater than one.
7 CUSTOMER PAYMNT
8 Q.,Please describe how the proposed incentive
9 amounts will be paid to the partièipants.
10 A.For participants in the Timer Option and
11 Dispatchable Interruption Options, the fixed portion of the
12 incentive will be paid as a credit on their bills. The
13 variable portion of the incentive payment for the
14 Dispatchable Interruption Options will be paid in the form
15 of a check issued no more than 60 days after the August
16 15th end date of the Program Season.
17 Q.Why is the Company proposing that the
18 variable portion of the incentive be paid by check after
19 the end of the Program?
20 A.By using this method of payment, the Company
21 can avoid issues with its billing system. It will also
22 highlight to the participants that they are paid the fixed
23 incentive through the bill credit and that the variable
PENGILLY, DI 23
Idaho Power Company
1 portion of the payment is based on the amount of time the
2 Program operates.
3 REVISED SCHEDULE 23
4 Q.Has the Company prepared a revised Schedule
5 23, Irrigation Peak Rewards Program, which reflects the
6 proposed modifications to the Program?
7 A.Yes. Idaho Power included Schedule 23,
8 Irrigation Peak Rewards Program, as an attachment to the
9 Company's Application in legislative and final format.
10 Q.Are there any other changes to Schedule 23
11 that should be pointed out?
12 A.Yes. The Company is proposing to add
13 clarifying language regarding participation in the Program.
14 Specifically, language has been added to indicate that
15 Program participation may be limited based on the Company's
16 need for peak load reduction.
17 In addition, the Company is proposing a housekeeping
18 clarification to indicate that customers participating
19 under Dispatchable Option 3 have the flexibility to choose
20 which irrigation pumps will be interrupted and how the
21 pumps will be interrupted during each dispatchable load
22 control event.
23 Q.Does this conclude your testimony?
24 A.Yes, it does.
PENGILLY, DI 24
Idaho Power Company