20081110Tatum Direct.pdf

RECEIVED
2008 HOV - 7 PH~: 52
IDAHO PUBLIC
UTlLlTIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY i S PETITION FOR APPROVAL
OF CHAGES TO THE IRRIGATION
PEAK REWARS PROGRA i AND FOR
AUTHORITY TO RECOVER THE COST
OF THE PROGRA IN THE PCA
CASE NO. IPC-E-08-23
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TIMOTHY E. TATUM
1 Q.Please state your name and business address.
2 A.My name is Timothy E. Tatum and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what
5 capacity?
6 A.I am employed by Idaho Power Company
7 ( "Company") as the Manager of Cost of Service in the
8 Pricing and Regulatory Services Department.
9 Q.Please describe your educational background.
10 A.I received a Bachelor of Business
11 Administration degree in Economics from Boise State
12 University in 2001. In 2005, I earned a Master of Business
13 Administration degree from Boise State University. I have
14 also attended electric utility ratemaking courses including
15 "Practical Skills for the Changing Electrical Industry," a
16 course offered through New Mexico State University's Center
17 for Public Utilities; "Introduction to Rate Design and Cost
18 of Service Concepts and Techniques" presented by Electric
19 Utilities Consultants, Inc.; and Edison Electric
20 Institute's "Electric Rates Advanced Course."
21 Q.Please describe your work experience with
22 Idaho Power Company.
23 A.I became employed by Idaho Power Company in
24 1996 as a Customer Service Representative in the Company's
TATUM, DI 1
Idaho Power Company
1 Customer Service Center. In June of 2003, after seven
2 years in customer service, I began working as an Economic
3 Analyst on the Energy Efficiency Team. As an Economic
4 Analyst, I maintained proper accounting for Demand-Side
5 Management ("DSM") expenditures, prepared and reported DSM
6 program accounting and activity to management and various
7 external stakeholders, conducted cost-benefit analyses of
8 DSM programs, and provided DSM analysis support for the
9 Company's 2004 Integrated Resource Plan ("IRP").
10 In August of 2004, I accepted a position as a
11 Pricing Analyst in Pricing and Regulatory Services. As a
12 Pricing Analyst, I provided support for the Company's
13 various regulatory activities, including tariff
14 administration, regulatory ratemaking and compliance
15 filings, and the development of various pricing strategies
16 and policies.
17 In August of 2006, I was promoted to Senior Pricing
18 Analyst. As a Senior Pricing Analyst, my responsibilities
19 were expanded to include the development of complex
20 financial studies to determine revenue recovery and pricing
21 strategies. I prepared the Company's cost-of-service
22 studies submitted as part of Case Nos. IPC-E-07-08 and IPC-
23 E-08-I0 and served as the Company's cost-of-service witness
24 in both cases.
ThTUM, DI 2
Idaho Power Company
1 In September of 2008, I was promoted to Manager of
2 Cost of Service. As Manager of Cost of Service I oversee
3 the Company's cost-of-service activities, such as power
4 supply modeling, jurisdictional separation studies, class
5 cost-of-service studies, and marginal cost studies.
6 Q.What is the scope of your testimony in this
7 proceeding?
8 A.My testimony will describe in detail a
9 number of proposed changes to the Irrigation Peak Rewards
10 Program, Schedule 23.
11 Q.Please provide an overview of the current
12 Irrigation Peak Rewards Program.
13 A.The Irrigation Peak Rewards Program,
14 Schedule 23 (the "Program") is a voluntary load control
15 program currently available to agricultural irrigation
16 customers with irrigation pumps having a cumulative
17 horsepower rating of 75 or greater. The purpose of the
18 Program is to produce a decrease in the Company's system
19 summer peak load by turning off specified irrigation pumps
20 between the hours of 4:00 P.M. and 8:00 P.M. on either one,
21 two, or three weekdays per week during the months of June,
22 July, and August.
23 Under the Program, the Company turns off specified
24 irrigation pumps on the customer's side of a metered
ThTUM, DI 3
Idaho Power Company
1 service point ("Metered Service Point") during summer
2 weekdays with the use of an electric switch ("Timer"). In
3 exchange for allowing the Company to turn off specified
4 irrigation pumps, participating Customers receive a monthly
5 monetary incentive ("Demand Credit") paid on the basis of
6 the kilowatt ("kW") reduction as measured by the customer's
7 monthly Billing Demand.
8 Q.Did the Company develop the proposed changes
9 to the Program with input from parties external to Idaho
10 Power?
11 A.Yes. As part of the settlement Stipulation
12 in Case No. IPC-E-07-08, approved by the Idaho Public
13 Utilities Commission ("IPUC" or "the Commission") on
14 February 28, 2008, through Order No. 30508, all parties to
15 that matter agreed that, prior to June 19, 2008, the
16 Company would convene a working group ("Workshop") where
17 interested parties would discuss potential modifications to
18 the Program and related issues.
19 Consistent with the Commission's Order, on June 11,
20 2008, the Company hosted the Workshop at its Mini-Cassia
21 office in Heyburn, Idaho. Attendees of the Workshop
22 included representatives of the Idaho Irrigation Pumpers
23 Association ("IIPA"), Idaho Power agricultural irrigation
24 customers, Commission Staff, and Company representatives.
TATUM, DI 4
Idaho Power Company
1 Q.What were the specific objectives of the
2 Workshop according to the settlement Stipulation in Case
3 No. IPC-E-07-08?
4 A.According to the terms of the Stipulation,
5 the purpose of the Workshop would be to discuss (1) the
6 operation and results of the current Program, (2) the
7 design and implementation of a dispatchable demand response
8 pilot program for the 2009 irrigation season, (3) the
9 methodology used in determining the amount of the incentive
10 payments for both the Program and the dispatchable pilot
11 program, (4) possible improvements to the joint marketing
12 efforts that could improve participation in the demand
13 response programs, and (5) possible additional steps needed
14 to ensure that the effects of the irrigation demand
15 response programs are adequately reflected in Idaho Power's
16 load research samples for the irrigation class and the
17 system as a whole.
18 Q.Please summarize the issues discussed at the
19 Workshop.
20 A.The Company began the Workshop by providing
21 a brief review of the Program's operational results for
22 2007. After the Company completed its 2007 operational
23 review, IIPA presented a number of potential modifications
24 to the Program for the group's consideration. IIPA's first
TATUM, DI 5
Idaho Power Company
1 recommendation included the implementation of a
2 dispatchable load control option for customers with pump
3 sizes of 30 HP and above. IIPA's recommendation was
4 modeled after the irrigation demand response program
5 currently operated by Rocky Mountain Power in Eastern
6 Idaho. Secondly, IIPA recommended that the Workshop
7 attendees consider the potential of using one-way
8 communication switches, similar to those used in the
9 Company's residential load control program, to turn off
10 irrigation pumps below 30 HP in size. This second option
11 was presented as a potentially cost effective way to
12 broaden the program's availability to include customers
13 with smaller pump sizes.
14 Following IIPA's presentation, Idaho Power presented
15 a proposal for a dispatchable load control program design.
16 In its presentation, the Company detailed the process that
17 was used to evaluate potential program designs, including
18 the economic and operational considerations that guided the
19 analysis process.
20 Q.Did the Workshop include a discussion of
21 possible improvements to the joint marketing efforts of the
22 Company and IIPA to improve participation in the Program?
23 A.Yes. The Workshop attendees discussed
24 several possible modifications to the marketing efforts for
TATUM, DI 6
Idaho Power Company
1 the Program. These discussions ultimately led to an
2 enhanced marketing strategy that includes an enhanced
3 commitment from IIPA to actively encourage its membership
4 to participate in the Program. i will discuss the
5 Company's role in the enhanced marketing strategy in
6 greater detail later in my testimony.
7 Q.Did the Workshop include a discussion of
8 possible additional steps needed to ensure that the effects
9 of the irrigation demand response programs are adequately
10 reflected in Idaho Power's load research samples for the
11 irrigation class and the system?
12 A.Yes. During the Workshop, the Company
13 presented the steps it has taken to modify the method used
14 to derive the coincident peak demand values that better
15 reflect the impact that the Program has on the Company's
16 peak demands. Idaho Power uses load research data to
17 develop the class coincident peak demands for the customer
18 classes that do not have interval metering capabilities.
19 Class coincident demands are used to allocate demand-
20 related costs in the Company's class cost-of-service
21 studies. The new method of deriving class coincident peak
22 demands was subsequently applied in the class cost-of-
23 service study prepared as part of the Company's 2008
24 general rate case proceeding, Case No. IPC-E-08-10.
TATU, DI 7
Idaho Power Company
1 Q.Was there a consensus reached or action
2 items assigned at the conclusion of the Workshop?
3 A.Yes. Following the presentations by the
4 Company and IIPA, attendees of the Workshop openly
5 discussed the proposed Program modifications. The group
6 ultimately came to agreement that a properly designed
7 dispatchable irrigation demand response program had
8 significant potential to cost-effectively reduce peak
9 dèmand and, if implemented, would be in the public's
10 interest. At the conclusion of the Workshop, the Company
11 agreed to research and analyze the set of recommended
12 Program design options to verify viability and cost
13 effectiveness. Furthermore, the Company agreed to discuss
14 with IIPA and Staff its findings and recommendations upon
15 completion of such research and analysis prior to making a
16 filing with the Commission.
17 Q.Did the Company fulfill its commitment to
18 engage the IIPA and Commission Staff in the research and
19 analysis process following the Workshop?
20 A.Yes. In the weeks following the Workshop,
21 the Company engaged in an iterative research and analysis
22 process involving IIPA and the Commission Staff that
23 included two phone conference workshops. These efforts
24 ultimately led to the parties indentifying and agreeing
TATUM, DI 8
Idaho Power Company
1 upon a revised Program design. The Company shared plans
2 for a revised Program with the Energy Efficiency Advisory
3 Group ("EEAG") at the October 2, 2008, meeting and received
4 comments and general support for the recommendations from
5 the EEAG. The proposed modifications that emerged from
6 this cooperative approach will serve to increase both the
7 cost-effective load reduction and broader availability of
8 the Program.
9 Q.Please provide an overview of the proposed
10 modifications to the Program that resulted from the
11 collaborative Workshop process?
12 A.The Workshop and subsequent collaborative
13 research and analysis process resulted in the following
14 proposed modifications:(1) the addition of a set of
15 dispatchable interruption options that will allow the
16 Company to remotely dispatch service interruptions to
17 participating irrigation pumps, (2) a broadened
18 availability of the Program that will provide the vast
19 majority of agricultural irrigation customers the
20 opportunity to participate, (3) a reduction in the number
21 of weeks over which the Program is operated annually from
22 the three summer months of June through August to a six
23 week period, June 15 through July 31 ("Program Season") ,
TATUM, DI 9
Idaho Power Company
1 and (4) a modified incentive structure that aligns with the
2 new Program's design.
3 Q.Please describe the proposed set of
4 dispatchable interruption options that will allow the
5 Company to remotely dispatch service interruptions to
6 participating irrigation pumps.
7 A.There are three separate dispatchable
8 interruption options proposed as part of the revised
9 Program.Under the first dispatchable interruption option,
10 Dispatchable Option 1,the Company will install a
11 dispatchable one-way communication load control device that
12 will be connected to the electrical panel (s) servicing the
13 irrigation pumps associated with the Metered Service Points
14 enrolled in the Program.The Load Control Device utilized
15 under Dispatchable Option 1 will provide the Company the
16 ability to send a signal that will interrupt or not allow
17 the associated irrigation pumps to operate during
18 dispatched load control events.Dispatchable Option 1 is
19 designed to appeal to customers with smaller pump sizes;
20 however, there is no pump- size restriction under this
21 option.
22 Under the second dispatchable interruption option,
23 Dispatchable Option 2,the Company wi 1 1 install a
24 dispatchable load control device capable of two-way
TATUM, DI 10
Idaho Power Company
1 communication that will be connected to the electrical
2 panel (s) servicing the irrigation pumps associated with the
3 Metered Service Points enrolled in this Program.The load
4 control device utilized under Dispatchable Option 2 will
5 provide the Company and the Customer remote control and
6 monitoring of the associated irrigation pumps.Under this
7 option, the Company will use this technology to send a
8 signal that will interrupt or not allow the irrigation
9 pumps to operate during dispatched load control events. As
10 with Dispatchable Option 1,there is no pump-size
11 restriction under this option.The Company expects that
12 the majority of participating customers will choose to
13 participate under Dispatchable Option 2.
14 The third dispatchable interruption option,
15 Dispatchable Option 3,is a dispatchable interruption
16 option available only to customers with metered service
17 points with interval metering having more than one pump and
18 at least 1,000 cumulative HP.Under this Dispatchable
19 Option, eligible Customers can choose to either (1) have
20 service interrupted using a dispatchable two-way
21 communication Load Control Device, as in Dispatchable
22 Option 2, or (2) manually interrupt electric service to
23 participating irrigation pumps during load control events.
TATUM, DI 11
Idaho Power Company
1 Q.How will the availability of the Program be
2 broadened under proposed Program design?
3 A.The vast majority of agricultural
4 irrigation customers will have the opportunity to
5 participate in the revised Program. The current Program is
6 available only to agricultural irrigation customers with
7 irrigation pumps having a cumulative horsepower rating of
8 75 or greater. Under the proposed Program design, all
9 pumps sizes will be eligible for participation.
10 Q.What is the rationale for allowing all pumps
11 sizes to become eligible for participation in the Program?
12 A.During the Workshop discussions, the IIPA
13 and other agricultural irrigation customers expressed their
14 desire to work toward broadening the availability of the
15 Program to increase participation and maximize cost-
16 effective load reduction. Two recommendations surfaced as
17 potentially viable options. The first recommendation
18 included expanding the Program eligibility criteria to
19 allow participation by customers with irrigation pumps
20 having a cumulative horsepower rating of below 75 HP
21 ("Small Pumpers"). The second recommendation involved
22 adding additional flexibility into to the Program to enable
23 more customers with very large irrigation systems of 1,000
24 HP and greater to participate ("Large Pumpers").
TATUM, DI 12
Idaho Power Company
1 Q.Why does the current Program prohibit
2 participation by customers with irrigation pumps having a
3 cumulative horsepower rating of below 75 HP?
4 A.The provision to exclude Small Pumpers from
5 participation in the Program has historically been driven
6 by economics. The Company's past economic analyses have
7 shown that pumps below approximately 100 HP are not cost-
8 effective additions to the Program from a utility cost
9 perspective. That is, the fixed investment required for
10 participation in the Program cannot be adequately offset by
11 the relatively low load reduction benefits provided by
12 these smaller irrigation systems. In order to maintain the
13 cost effectiveness of the current Program, an Installation
14 Fee of $250.00 is assessed to those customers with
15 irrigation pumps between 75 and 99 cumulative horsepower
16 per Metered Service Point. Consistent with this approach,
17 the following expanded Installation Fee schedule is
18 proposed:
Horsepower (HP)Dispatchable Option Timer
1 2 3 *Option
Less than 30 HP $500 $1,000 N/A $500
From 30 to 49 HP $0 $500 N/A $350
From 50 to 74 HP $0 $0 N/A $350
From 75 to 99 HP $0 $0 N/A $250
Greater than 99 HP $0 $0 N/A $0
1920 Note: (*) An Installation Fee will not be assessed under21 Dispatchable Option 3.
TATUM, DI 13
Idaho Power Company
1 The proposed Installation Fee structure will allow
2 more customers to become eligible for participation in the
3 Program while maintaining its cost effectiveness.
4 Q.Do the current Program provisions explicitly
5 restrict Large Pumpers from participation?
6 A.No. The current Program does not explicitly
7 restrict Large Pumpers from participation; however, the
8 complexity of these large, multiple-pump irrigation systems
9 often prohibits an interruption of service to all the pumps
10 served by a single Metered Service Point, which is required
11 undèr the provisions of the current Program. The proposed
12 Dispatchable Option 3 provides an opportunity for the Large
13 Pumpers to participate in the Program by allowing them the
14 flexibility to choose which irrigation pumps will be
15 interrupted during each dispatched load control event.
16 Q.Why is the Company proposing to reduce the
17 number of weeks over which the Program is operated
18 annually?
19 A.As part of the research and analysis process
20 that led to the proposed Program design, the internal
21 Program design team at Idaho Power held several discussions
22 with subject matter experts that work within the generation
23 dispatch and power supply planning functions of the
24 Company. According to perspectives shared by
TATUM, DI 14
Idaho Power Company
1 representatives from the generation dispatch and power
2 supply planning groups, the value of the load reduction
3 capability of the Program is in its ability to reduce loads
4 when the demand on the electrical system is at or near the
5 annual system peak. Furthermore, these discussions
6 confirmed that currently there is a near zero probability
7 that Idaho Power's electrical system will experience a
8 annual system peak demand outside of the time period of
9 June 15 through July 31. With that in mind, the Program
10 Season was revised to align with the June 15 through July
11 31 period.
12 Q.How will the incentive payments be
13 calculated under each dispatchable interruption option?
14 A.Under the dispatchable interruption options,
15 customers will receive a financial incentive in the form of
16 a bill credit applied to the monthly bills during June and
17 July for each Metered Service Point enrolled in the
18 Program. The bill credit will include a demand-based
19 component ("Demand Credit") and an energy-based component
20 ("Energy Credit"). Under Dispatchable Options 1 and 2, the
21 Demand Credit will be based upon the monthly Billing
22 Demand, as measured in kW. The Energy Credit provided
23 under these options will be based upon the monthly energy
24 usage, as measured in kWh, for the associated Billing
TATUM, DI 15
Idaho Power Company
1 Period. Under Dispatchable Option 3, the Demand Credit
2 will be based upon the monthly Billing Demand minus the
3 average demand, as measured in 15 minute intervals, during
4 each load control event initiated during a Billing Period.
5 The Energy Credit under this option will be based upon a
6 calculated value, as measured in kWh. The energy basis for
7 Energy Credit will be calculated separately for each
8 Billing Period by multiplying the calculated kW amount used
9 in the Demand Credit calculation by the ratio of the
10 monthly energy usage to the Billing Demand for the
11 associated Billing Period.
12 Q.How does the proposed incentive structure
13 differ from the current incentive structure?
14 A.Under the current Program design, incentives
15 are paid on a demand basis only according to the following
16 schedule:
Timer Option Demand Credit ($/kW)
One Weekday $2.01
Two Weekdays $3.36
Three Weekdays $4.36
17
18 Under the proposed Program design, incentives would be paid
19 on a demand basis and an energy basis (except for the "One
20 Weekday" Timer Option, which is paid on demand basis only)
21 according to the following schedule:
TATU, DI 16
Idaho Power Company
Dispatchable Options
Dispatchable Demand Credi t Energy Credit
Option ($/kW)($/kWh)
1 $ 4.65 $0.031
2 $ 4.65 $0.031
3 $ 4.65 $0.031
Timer Options
Demand Credit Energy Credi t
Timer Option ($/kW)($/kWh)
One Weekday $ 3.15 $ 0.000
Two Weekdays $ 4.65 $ 0.002
Three
Weekdays $4.65 $0.007
1
2 Q.Why does the proposed incentive structure
3 include the addition of an energy-based incentive amount?
4 A.Since the inception of the Program, the
5 Company has maintained that it is important that the Demand
6 Credit amount remain below the Demand Charge under Schedule
7 24, Agricultural Irrigation Service. This ensures that
8 customers participating in the Program are not incented to
9 turn on a pump when they otherwise would not simply to earn
10 a bill credit. The proposed incentive structure recognizes
11 that notion by including an energy-based incentive amount
12 which allows for additional incentive dollars to be
13 provided to participating customers while maintaining a
14 Demand Credit at or below the current Demand Charge under
15 Schedule 24.
TATUM, DI 17
Idaho Power Company
1 Q.What is the justification for the increased
2 incentive amounts under the proposed incentive structure?
3 A.As discussed earlier in my testimony, the
4 value of this Program is in its ability to reduce loads
5 when the demand on the electrical system is at or near the
6 annual system peak. In other words, this Program allows
7 the Company to defer or avoid the procurement of additional
8 generation capacity to serve peak demand. Consistent with
9 that concept, the cost basis for the incentive payments
10 provided under the Program is the levelized cost per annual
11 kW of a simple-cycle combustion turbine. Because the
12 monthly incentive payments are based upon the annual
13 avoided capacity cost, the reduced Program Season requires
14 a larger monthly incentive payment in order to pay the same
15 annual incentive amount. Furthermore, the potential
16 average load reduction of the Program during the reduced
17 Program Season is greater as the Program Season is
18 concentrated into a period when irrigation loads are at
19 their highest.
20 Q.Has the Company performed an analysis to
21 determine that the proposed Program design is cost
22 effective?
23 A.Yes. The economic analysis that ultimately
24 led to the modified Program design, including the proposed
TATUM, DI 18
Idaho Power Company
1 incentive structure, is detailed on Exhibit No.1. Exhibit
2 No. 1 is a memorandum from Pete Pengilly, Idaho Power
3 Customer Research and Analysis Leader, that describes the
4 methodology used to determine that the prqposed Program is
5 cost effective. The memorandum details the underlying
6 assumptions and financial inputs used in the analysis as
7 well as the analysis results.
8 Q.Under the proposed Dispatchable Options, are
9 customers permitted to opt-out of an individual load
10 control event without having to completely terminate
11 participation in the Program?
12 A.Yes. Customers selecting Dispatchable
13 Options 1 and 2 may opt-out of a load control event up to
14 five times per season any time prior to or during a load
15 control event. Each time a customer chooses to opt-out of
16 a load control event a fee of $0.005 per kWh will be
17 assessed based upon the current month's energy usage.
18 Under Dispatchable Option 3, customers may opt-out of a
19 load control event at any time. However, due to the nature
20 of the bill credit calculation under Dispatchable Option 3,
21 customers choosing to opt-out of a load control event will
22 cause the average demand during load control events to
23 increase, thereby, reducing the monthly bill credit amount.
TATUM, DI 19
Idaho Power Company
1 Q.Is the Company proposing any changes to the
2 Timer Option under the Program?
3 A.No. Aside from shortening the Program
4 Season and the associated change in the incentive structure
5 as described earlier in my testimony, the mechanics of the
6 Timer Option will remain unchanged.
7 Q.If the Commission approves the proposed
8 modifications to the Program, how does the Company plan to
9 communicate the new Program design to eligible customers?
10 A.The Company plans to solicit participation
11 in the Program for the 2009 Program Season using a number
12 of methods. First, information packets will be mailed to
13 all agricultural irrigation customers explaining the
14 Program in detail and inviting them to participate. This
15 packet of information will be customized for each customer
16 and will include a listing of the customer's eligible
17 Metered Service Points and an estimate of the potential
18 incentive amount for each Metered Service Point based on
19 the associated 2008 bill history. Second, Idaho Power, in
20 conjunction with county extension services and other
21 irrigation/agricultural entities, will sponsor 7 to 10
22 irrigation workshops across the Company's service
23 territory. The Peak Rewards program will be one of the
24 specific topics covered. These workshops will present
TATUM, DI 20
Idaho Power Company
1 details of how the incentives are calculated, demonstrate
2 how the equipment works, and how customers will be able to
3 operate their irrigation pumps using the equipment. Third,
4 Idaho Power's local agricultural representatives will be
5 available to answer questions and help market the Program
6 on an ongoing basis. Finally, Idaho Power will advertise
7 the Program in various agricultural publications throughout
8 the winter and early spring to raise awareness and to
9 inform customers of the Program.
10 Q.You mentioned that the Company plans to
11 educate customers on the benefits of the revised Program at
12 workshops over the winter months. Does the Company plan to
13 market the revised Program prior to the Commission issuing
14 an Order on this matter?
15 A.No. The Company plans to initiate the
16 proposed Program marketing strategy immediately following
17 the issuance of the Commission's Order in this proceeding.
18 Should the Commission approve the settlement Stipulation,
19 an Order issued by January 2, 2009, would allow adequate
20 time to effectively market the Program prior to the 2009
21 Program Season.
22 Q.What impact are the proposed modifications
23 expected to have on the Program's ability to cost
24 effectively reduce peak demand?
TATUM, DI 21
Idaho Power Company
1 A.In 2009, the Program is expected to provide
2 and overall peak load reduction of approximately of 144 MW
3 (including losses). The Company estimates that 800 Metered
4 Service Points will be enrolled in the Dispatchable Options
5 resulting in a peak load reduction of about 128 MW
6 (including losses). Idaho Power estimates that the number
7 of Metered Service Points enrolled in the Timer Option will
8 decrease to 375 resulting in a peak load reduction of
9 approximately 16 MW (including losses). The overall
10 increase in peak load reduction expected in 2009 due to the
11 proposed Program modifications is estimated to be 108 MW
12 (including losses) .
13 Q.Is the Company planning to test the
14 effectiveness of the proposed Dispatchable Options on a
15 pilot basis in 2009?
16 A.No. The Dispatchable Options are proposed
17 as permanent additions to the current Schedule 23,
18 Irrigation Peak Rewards Program. However, to ensure that
19 the installation of the load control devices can be
20 completed prior to the start of the Program Season, the
21 Company proposes to limit participation under the
22 Dispatchable Options to 1,000 Metered Service Points in
23 2009.
TATUM, DI 22
Idaho Power Company
1 Q.Do you expect the proposed participation
2 limit to negatively impact the Program's potential to
3 reduce peak loads in 2009?
4 A.No. As detailed earlier in my testimony,
5 the Company estimates participation under the Dispatchable
6 Options to be approximately 800 Metered Service Points in
7 2009. Therefore, limiting participation to 1,000 Metered
8 Service Points is not expected to impact the Program's
9 potential to reduce peak loads in 2009.
10 Q.Have you prepared a revised Schedule 23,
11 Irrigation Peak Rewards Program, which reflects the
12 proposed modifications to the Program?
13 A.Yes. Included as Exhibits A and B to the
14 settlement Stipulation in this proceeding is a revised
15 Schedule 23, Irrigation Peak Rewards Program, in
16 legislative and final format.
17 Q.What are the proj ected costs of the proposed
18 Program over the next three years, 2009 through 2011?
19 A.Idaho Power estimates the Program will grow
20 from an estimated 800 Metered Service Points in the first
21 year to approximately 1,400 in the third year. The
22 following table details the proj ected annual Program costs
23 over the period of 2009 through 2011.
TATUM, DI 23
Idaho Power Company
Idaho Equipment &Other ProgramYearPower Incentives Total
Labor Install Labor Admin.
2009 $110,000 $1,485,000 $230,000 $4,864,000 $6,689,000
2010 $113,000 $557,000 $302,000 $8,575,000 $9,547,000
2011 $117,000 $557,000 $374,000 $9,798,000 $10,846,000
1
2 Q.How does the Company propose to fund the
3 costs associated with the modified Program?
4 A.Currently, this Program is funded through
5 the Energy Efficiency Rider, Schedule 91 ("Rider").
6 However, the increased costs associated with the proposed
7 Program modifications cannot be adequately funded at the
8 current Rider funding level of 2.5 percent of base
9 revenues. At the current level, the Rider provides
10 approximately $17 million annually. If this Program is to
11 be funded by the Rider, the annual funding amount would
12 have to be increased to approximately $27 million or 4
13 percent of base revenues. Considering there are other
14 planned energy efficiency activities that will demand
15 additional Rider funding beyond the current level, Mr. Said
16 proposes an alternative funding strategy for this Program
17 that he describes in detail in his testimony.
18 Q.Does this conclude your testimony?
19 A.Yes, it does.
TATUM, DI 24
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-08-23
IDAHO POWER COMPANY
TATUM, 01
TESTIMONY
EXHIBIT NO.1
MEMORANDUM
Date:
Prepared For:
Prepared By:
Subject:
October 22, 2008
Tim Tatum, Pricing and Regulatory Services
Pete Pengily, Customer Relations and Energy Efficiency
Irrigation Peak Rewards,
2009 Dispatchable Program Option
. Cost-Effectiveness
Idaho Power develops cost-effectives analyses for each demand response and energy efficiency
program offered to its customers. The first step is to obtain the demand-side management (DSM)
alternative costs from the most recent Integrated Resource Plan (lRP). The cost-effectiveness
analysis for the Irrigation Peak Rewards program is based on the 2006 IRP with values
corresponding with year 2009 (see figure 1 , Year 4).
Figure 1. DSM alternative costs from the 2006 IRP, Technical Appendix D, page 68.
DSM Alternativ Energy Cost ($JM)
12
SONP
$ 91.08
$ 95.30
$ 88.97
$ 88.12
$ 67.14
$ 67.81'
$ 68.94
$ 71.25
$ 73.30
$ 75.73
$ 78.91
$ 82.37
$ 85.26
$ 89.35
$ 92.6'4
$ 86.04
$ 89.19
$ 93.13
$ 95.86
$ 99.47
$ 93.36
$ 97.22
$ 100.74
$ 104.46
$ 108.97
$ 110.64
$ 112.32
$114.01
$ 115.71
$ 117.42
Seasonal Market Price Forecast
SMP SOFP NSMP
$ 68.57 $ 51.54 $ 77.61
$ 69.89 $ 51.61 $ 78.95
$ 65.98 $ 48.07 $ 68.96
$ 66.39 $ 48.52 $ 68.15
$ 50.43 $ 37.03 $ 52.75
$ 55.93 $ 41.28 $ 54.30
$ 67.85 $ 50.72 $ 64.61
$ 71.71 $ 54.18 $ 68.18
$ 74.02 $ 56.01 $ 70.06
$ 78.45 $ 59.19 $ 74.07
$ 82.40 $ 62.08 $ 78.96
$ 90.38 $ 66.94 $ 86.37
$ 94.36 $ 70.70 $ 90.27
$ 98.01 $ 75.25 $ 95.24
$ 102.92 $ 79.15 $100.11
$ 97.28 $ 75.60 $ 94.42
$ 104.05 $ 80.51 $ 101.25
$ 108.84 . $ 84.94 $ 105.87
$ 114.48 $ 90.26 $ 111.23
$ 120.35 $ 96.05 $ 118.21
$ 123.96 $ 98.93 $ 121.75
$ 127.68. $ 101.90 $ 125.40
$ 131.51 $ 104.95 $ 129.17
$135.46 $ 108.10 . $ 133.04-,- ...... ......"
$ 139.52 $ 111.35 $ 137.03
$ 143.71 $ 114.69 $ 141.14
$ 148.02 $ 118.13 $ 145.38
$ 152.46 $ 121.67 $ 149.74
$ 157.03 $ 125.32 $ 154.23
$ 161.74 $ 129.08 $ 158.86
$ 6'5.59
$ 65.64
$ 55.61
$ 55.39
$ 42.31
$ 42.99
$ 51.51
$ 54.33
$ 56.05
$ 59.74
$ 63.83
$ 69.54
$ 72.64
$ 76.92
$ 80.34
$ 76.63
$ 81.28
$ 85.53
$ 90.19
$ 95.55
$ . 913.2
$ 1 01.37
$ 1 04.41
$ 1 07.55
$ 110.77
$114.10
$ 117.52
$ 121.04
$ 124.68
$ 128.42
Exhibit No. 1
Case No. IPC-E-08-23
T. Tatu - Idaho Power Company
Page lof3
Fixed plant costs were combined with the variable costs for developing total alternative costs.
For the peak alternative, a 162MW Simple Cycle Combustion Turbine plant was used as the cost
basis. The levelized capacity cost factors applied were $64.92/KW/year. .
Next, Idaho Power inputs assumptions, costs, and financial factors into a spreadsheet model that
calculates the benefits and costs to offer the Program. The cost-effectiveness provided in figure 2
is based on first year participation estimated to be 800 service locations.
Figure 2. Irrigation Peak Rewards Dispatchable Program Option Cost-Effectiveness Model
Irrigation Peak Rewards Dispatchable Program
Benefit/Cost Analysis2009 _
64.92
1~.00%
10.90%
6.9~%
~.OO%
800
190
75%
114,000
128,820
4,560,000
The cost-effectiveness módel calculates the benefits of the Program by multiplying the expected
load reduction of the Program by the DSM alternative capacity cost. Then adds the energy
savings, which are grossed up for line losses and multiplied by the difference between the energy
costs during the summer on peak time period and the sumer off peak time period presented infigue 1. .
This calculation with 800 locations and an average capacity of 190 k W per location with an
estimated 75% realization (which estimates the probability that the pump is on during a control
event) and 13% summer on peak line loss equals an estimated load reduction of 128 MW and a
shifted energy amount of 5,152,800 kWhs. Applying the $64.92 per kW DSM alternative cost to
the 128 MW peak load reduction and adding the calculated shifted energy benefit of $118,314
provides an avoided cost benefit of approximately $8.5 millon.
Exhibit No. i
Case No. IPC-E-08-23
T. Tatum - Idaho Power Company
Page 2 of3
The model calculates the total cost to the utility including: incentives, program administration
and promotion, equipment installation and maintenance, and evaluation. The customer incentive
of $4.65 per kW plus $0.031 perkWh for the months of June and July is the largest cost to the
Program. This cost for 800 service points with an average capacity of 190kW is estimated to
equal $4,864,000. It is expected that in 2009 the equipment and installation and maintenance
will cost $1,677,600 and that program administration and marketing wil cost approximately
$148,000. In 2009 the total costs to Idaho Power are anticipated to be about $6.7 milion.
The total expected program costs and estimated total benefits results in a benefit/cost ratio of
1.27 for the first year of the Program. Figure 3 depicts a graph on a per kW basis of the estimated
benefits and costs pertaining to the program during 2009.
Figure 3. Irrigation Peak Rewards Dispatchable Option Benefit/Cost Results
I Irrigation Peak RewardsDispatchable Option - Benefit/Cost Comparison
$/kW/Year
$70.00
$60.00
$50.00
$40.00
o DSM Alt. Energy
Ii DSMAIt. Capacity
$30.00 o Program Administration
13 Equip., Install & Operation
$20.00
o Incentives
$10.00
2009 (1st yr est.)
In summar, Idaho Power believes the benefit/cost ratio of 1.27 is adequate for the first year of
the program based on the number of assumptions that have been applied in this analysis.
Although it is expected the program Will continue to grow in paricipation resulting in overall
increased costs, higher equipment costs are realized in the first year. Therefore, Idaho Power
expects the dispatchable program option wil remain cost-effective and viable as a program
offering in futue years.
Exhibit No. 1
Case No. IPC-E-08-23
T. Tatum - Idaho Power Company
Page 3 of3