20110201IPC to Staff 1-19.pdf

esIDA~POR~
An IDACORP Company
LISA D. NORDSTROM
Lead Counsel
Inordstromcmidahopower.com
January 31, 2011
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-10-46
IN THE MATTER OF THE APPLICA TlON OF IDAHO POWER COMPANY
FOR APPROVAL OF REVISIONS TO THE IRRIGATION PEAK REWARDS
PROGRAM, SCHEDULE 23
Dear Ms. Jewell:
Enclosed for filing please find an original and three (3) copies of Idaho Power
Company's Response to the First Production Request of the Commission Staff to Idaho
Power Company in the above matter.
Also enclosed are four (4) copies of a non-confidential disk containing documents
being produced in response to Staff's First Production Request.
Very truly yours,
tf~~?L~
LDN:csb
Enclosures
1221 W. Idaho St. (83702)
P.O. 80x 70
Boise. ID 83707
LISA D. NORDSTROM (ISB No. 5733)
DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
InordstromCâidahopower.com
dwalkerCâidahopower.com
i-- 4~- .
iUi J JAN 3; Plitt: 50
Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
APPROVAL OF REVISIONS TO THE
IRRIGATION PEAK REWARDS
PROGRAM, SCHEDULE 23
)
) CASE NO. IPC-E-10-46
)
) IDAHO POWER COMPANY'S
) RESPONSE TO THE FIRST
) PRODUCTION REQUEST OF THE
) COMMISSION STAFF TO IDAHO
) POWER COMPANY
)
COMES NOW, Idaho Power Company ("Idaho Powet' or "Company"), and in
response to the First Production Request of the Commission Staff to Idaho Power
Company dated January 10, 2011, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 1
REQUEST NO.1: On page 3 of the Application, the Company "concluded that
its annual capacity need during the highest 60 hours of demand is expected to vary by
more than 50 percent (167 megawatts) during the next five years." Please describe all
the parameters used in the model to reach this conclusion, and provide all executable
electronic regression models, along with descriptions of accuracy (i.e., - descriptive
statistics).
RESPONSE TO REQUEST NO.1: The statement referred to in Staff's
Production Request No.1 is a conclusion drawn from Exhibit No.1 of Peter Pengilly's
direct testimony, page 4, column H, which shows the least Demand Response Target
as 155 megawatts ("MW") in 2012 and the greatest Demand Response Target as 322
MW in 2015; this is an increase of 52 percent. The Demand Response Targets in
column H are the values from column G, Achievable DR with 60 Hour Program, unless
the need demonstrated in column F is less. Please see the Excel file provided on the
enclosed CD containing an electronic copy of the table provided as part of this
response.
The response to this Request was prepared by Peter Pengilly, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 2
REQUEST NO.2: On pages 4 and 5 of the Application, the Company describes
the incentive payment for "Extended Interruption" participants. Please explain how the
Company arrived at the "Extended Interruption" Incentive amount. As part of your
response, explain how the Company arrived at the incentive difference between the
"Standard Interruption" and the "Extended Interruption." Please provide the supporting
executable electronic workpapers.
RESPONSE TO REQUEST NO.2: As demonstrated in the table on page 2 of
Exhibit No. 1 of the direct testimony of Peter Pengily, in the theoretical 2011 dispatch,
the Company only needs approximately 60 MW in the 8:00 p.m. to 9:00 p.m. hour to
keep the system demand from going up at the end of the load reduction event. Idaho
Power estimated the additional incentive level for the "Extended Interruption" that would
be necessary to encourage the desired participation. The Company also incorporated
this additional incentive into its cost-effectiveness model to assure that the program
remained cost-effective. The concept of this additional incentive was a result of the first
meeting with the Idaho Irrigation Pumpers Association, Inc., ("IIPA") in discussing the
proposed changes.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 3
REQUEST NO.3: On page 5 of the Application, the Company describes
changes to the way load reduction is calculated for the Dispatchable Option 3 credit
payment. Please fully explain why the Company chose to use "average demand
between 10:00 p.m. and 11 :00 a.m. MDT prior to an event" for calculating the load
reduction rather than average demand over the prior 24-hour period. Please provide
the supporting executable electronic workpapers.
RESPONSE TO REQUEST NO.3: Currently, the program kilowatts ("kW") for
the Dispatchable Option 3 participants are based on the maximum measured interval
demand during the 24-hour period immediately preceding an event. However, this
method does not always accurately represent the participants load prior to an event. In
the past, there have been a few instances where a participant has registered a high
demand by turning on extra pumps for a short period of time prior to an event, which did
not accurately represent his/her overall demand just prior to an event. The Company's
proposal to use an average kW would mitigate the affect of any singular spike in
demand. The Company chose to propose an average from 10:00 p.m. to 11 :00 a.m.
because many participants begin decreasing their loads prior to an event in order to be
assured that they achieve the demand reduction they want. Also, if the Company were
to use the 24 hours prior to an event and if the Company had two event days in a row,
then the prior 24-hour period of the second event would potentially have event hours
within the prior 24 hours. This could bring down the average demand for the customer
and misrepresent the demand that was actually reduced. The Company believes that
using the average demand between 10:00 p.m. and 11 :00 a.m. Mountain Daylight Time
prior to an event captures an accurate baseline of demand prior to an event.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 4
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 5
REQUEST NO.4: On page 8 of the 2009 Annual DSM Report, the Company
states "Next to distributed generation, the Company's demand response programs are
the least-cost resource for meeting summer peak loads over the 20-year IRP planning
period." Please compare the cost (per kW and kWh at generation) of the Irrigation Load
Control Program with the cost (per kW and kWh at generation) of the resources
anticipated to be necessary over the next 10 years. As part of your answer, please
explain your net present value (NPV) assumptions. Please provide the supporting
executable electronic workpapers.
RESPONSE TO REQUEST NO.4: The tab entitled Supply Side Resources on
the Excel spreadsheet provided on the enclosed CD contains all of the 30-year annual
expenses for the 6 different supply-side resources identified under the preferred
portolio for the first 10 year period of the 20-year planning horizon continued in the
2009 Integrated Resource Plan ("IRP"). Also contained within the Excel spreadsheet on
the tab entitled Demand Side Resources is the 20-year annual expense forecast for the
irrigation demand response program as forecasted for the 2009 IRP. The irrigation
program expenses are part of Table DSM-13, Demand Response Utilty Costs 2010-
2029, published as part of the 2009 IRP in Appendix C - Technical Appendix, page 106.
The Supply Side Resources worksheet explicitly shows the annual costs, including
annual capital costs, non-fuel operation and maintenance, property taxes and
insurance, mitigation expenses (Le., production tax credits, renewable energy credits),
and fuel costs for the following resources: wind (100 MW), combined cycle combustion
turbine (270 MW), geothermal (26 MW), Shoshone Falls upgrade (64 MW), and
Transmission at 6 percent capacity - Boardman to Hemingway (225 MW). These are
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 6
the resources identified that will be needed over the next 10 years based on the 2009
IRP preferred portolio.
Row 47 in the Supply Side Resources worksheet contains the levelized cost in
dollars per kilowatt-hour ("kWh") as reported in Figure 6.2, 30- Year Levelized Cost of
Production (at Stated Capacity Factors), on page 75 of the 2009 IRP.
Row 91 in the Supply Side Resources worksheet contains the levelized cost in
dollars per KW per month as reported in Figure 6.1, 30- Year Levelized Capacity (Fixed)
Costs, on page 74 of the 2009 I RP.
The net present value assumptions used for all calculations of both levelized
energy and capacity are based on the assumptions found in the Supply-Side Resource
Data, Financial Assumptions and Factors, table found on page 85 of Appendix C -
Technical Appendix of the 2009 IRP. All spreadsheet formula results on rows 47 and
91 are consistent with the data reported in the Levelized Resource Cost Tables and 30
Year Levelized Capacity (Fixed) Cost Per kW tables on pages 88 and 89 of the 2009
IRP, Appendix C - Technical Appendix.
In column Q on the Demand Side Resources worksheet, the irrigation levelized
costs per kW per month are reported consistent with results reported on page 74 of the
2009 IRP. Columns R-T contain levelized cost estimates based on various capacity
factors applied to the irrigation demand response program. Column R contains the
levelized cost per kWh based on 60 hours or maximum potential program output for the
current program design, while columns Sand T report estimated levelized energy at 40
and 30 hours of program operation, respectively. The results of the analysis and the
table on page 74 of the 2009 IRP show that next to distributed generation, the
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 7
Company's demand response programs are the least-cost resource for meeting
summer peak loads over the 20-year IRP planning period.
For Staffs convenience, the pages from the 2009 IRP referenced in this
response are provided on the enclosed CD. In addition, the 2009 IRP and appendices
can be found at: http://ww.idahopower.com/AboutUs/RatesRegulatory/Reports/default.cfm?state=id.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 8
REQUEST NO.5: On pages 16-17 of Pete Pengily's Testimony, he describes a
connection between the variabilty of forecasted demand in the resource adequacy
analysis and the Company's proposed 40 percent fixed and 60 percent variable
incentive payment. On page 17, lines 2-5, he says "the Company believes that the 60
percent variable payment structure is reflective of the variations in cost that would exist
under a variable participation approach." Please explain whether variability in the need
for demand response wil be the basis for determining the fixed versus variable
incentive structure moving forward. As part of your response, please explain why you
did not mirror the results of the projected demand response variability analysis by
setting the incentive payment at 50 percent fixed and 50 percent variable.
RESPONSE TO REQUEST NO.5: The variations in cost that would exist under
a variable participation approach, pointed out on pages 16-17 of Peter Pengily's direct
testimony, are a result of analysis performed during development of the 2011 IRP. The
Company plans to base future decisions upon similar analyses of future IRPs.
While the Company relied on the variabilty of the need for demand response to
help determine the approximate split between the variable and fixed portion of the
incentive, it also relied on the expertise of its agricultural engineer and program
specialist to propose a level of fixed versus variable incentives to retain participation
and maintain load reduction potentiaL.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 9
REQUEST NO.6: Page 17, lines 5-7 of Pete Pengily's Testimony, he states
"the Company anticipates that the proposed level of fixed incentive will be adequate to
retain current participants." Please describe the studies, reviews, or market research
used that supports the Company's conclusion. As part of your response, please provide
the supporting electronic workpapers (e.g. - program maturity or market saturation
evaluations ).
RESPONSE TO REQUEST NO.6: The Company relied on the expertise of its
agricultural engineer and program specialist to determine if the fixed incentive level
versus variable incentives was adequate to retain participation and maintain load
reduction potential.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 10
REQUEST NO.7: In executable electronic format, for 2010 please provide the:
a. Amount of money paid to irrigators in credit payments,
b. Number of annual events called per season,
c. Duration of each event,
d. Percentage of participants curtailed during each event,
e. Variation in hours curtailed for each participant during each event,
f. Total hours curtailed for each participant in each season. If the
maximum number of curtailed hours per participant was not used
during any particular season, please explain why.
RESPONSE TO REQUEST NO.7:
a. In 2010, Idaho Power paid approximately $11.5 milion in incentives to
Irrigation Peak Rewards participants.
b. Three dispatch events were called in 2010; a fourth event was scheduled
but canceled before it was actually dispatched.
c. All dispatch participants in the Irrigation Peak Rewards program were
dispatched for 4 hours. However, the start and end times were not the same for all
participants. In 2010, for all 3 dispatch events, the earliest event started at 3:00 p.m.
and the latest an event ended was 8:00 p.m. Please see the Excel spreadsheet
provided on the enclosed CD for the details of each dispatch event.
d. Assuming all dispatch devices were working correctly, all participants were
curtailed for each event.
e. Each dispatch participant was dispatched for the same number of hours
for each event even though the start and end times varied for different groups of
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 11
customers. Timer participants were turned off either 4, 8, or 12 hours per week
depending on which option they were participating under.The timers are
preprogrammed to start and stop interrptions based on the program season dates;
therefore, some customers wil have a different number of days for the first and last
weeks of the program season. Please see the Excel spreadsheet provided on the
enclosed CD for each group and the dispatch times.
f. Customers participating under the Timer Option were curtailed between
4:00 p.m. and 8:00 p.m. on 1, 2, or 3 weekdays per week depending on their level of
participation. Each dispatched participant in 2009 was dispatched for a total of 27 hours
of interruption. In 2010, each dispatch participant was dispatched for a total of 12 hours
of interruption. Please see the Excel spreadsheet provided on the enclosed CD.
An Idaho Power inter-departmental team decides the number of hours that Idaho
Powets demand response programs are dispatched. The team consists of
representatives from Power Supply Planning, Generation Dispatch, Regulatory Affairs,
Demand Response Program Specialists, Transmission Planning, Energy
Trading/Dispatch, and Compliance. The dispatch of these programs is based on the
load forecast, weather forecast, generation resource availability, transmission
availabilty, and purchased energy availabilty and price. The program was not used for
the maximum number of hours in 2010 because, based on the above factors, it was not
needed for the full 60 hours.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 12
REQUEST NO.8: What would interruptions have been in 2010 if the proposed
program incentive structure had been in place? How much money would have been
paid to participating irrigators in credit payments? How would administrative costs
change?
RESPONSE TO REQUEST NO.8: Idaho Power would probably have
dispatched the Irrgation Peak Rewards program one time in 2010 if the incentive
structure included in this filng was in effect. The Company would have paid
participating irrigators approximately 40 percent of the $11.5 milion incentives that were
actually paid to participants in 2010. However, the administrative costs would not have
changed.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -13
REQUEST NO.9: On Exhibit 2 of Pete Pengily's Testimony, the Company
provides a table ilustrating the modified incentive payment structure based on a
hypothetical participant with a 125 horsepower pump. Please provide the impact of
program changes on customers with the average or median size pumps.
RESPONSE TO REQUEST NO.9: The average horsepower of 2010
participants was 238 horsepower and the average demand for these participants was
184 kW. The table below is similar to the table presented in Peter Pengily's direct
testimony; however, the table below substitutes a hypothetical 238 horsepower pump.
Current Incentiv Structure Proposed Incentive Structure
238 Hp (184 kW)(100%Rxed & O%Variabl)(40% Rxed & 60% Variable)
A B C D E F G H I J
Fixed Fixed Total Fixed Fixed Variable Total % afFixed % of Current
($/kW)($/kWh)**$($JkW)($JkWh)**($/kWh)*$%%
Incentives $4.65 $ 0.031 $ 5.00 $0.0038 $ 0.35
o Events(O hrs)$1,711 $ 4,175 $5,887 $1,840 $512 $-$2,352 100%40%
3 Events(12 hrs)$1,711 $ 4,175 $5,887 $1,840 $512 $773 $3,125 75%53%
7 Events(28 hrs)$1,711 $ 4,175 $5,887 $1,840 $512 $1,803 $4,155 57%71%
15 Events (60 hrs)$1,711 $ 4,175 $5,887 $1,840 $512 $ 3,864 $6,216 38%106%
* kWh = kW demand x number of event hours
!** based on an assumed hours .&of 732 hours I
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 14
REQUEST NO. 10: Has the Company considered increasing the Dispatchable
Option 3 cumulative horsepower requirement for program participation? Has the
Company considered initiating a cumulative horsepower requirement for participation in
its other dispatchable options? In both cases, why were proposals not made?
RESPONSE TO REQUEST NO. 10: No, the Company has not considered
increasing the Dispatchable Option 3 cumulative horsepower requirement. Yes, the
Company has considered initiating a cumulative horsepower requirement for
participation in its other dispatchable options.
Prior to 2008, the Irrigation Peak Rewards program did have a minimum
cumulative horsepower requirement of 75 horsepower. However, based on past input
from the Idaho Public Utilties Commission ("Commission") Staff and the IIPA, in 2008
the Company removed the horsepower limit and instead charged smaller horsepower
service locations an installation fee to participate. These fees were implemented to help
cover the cost of installation to keep the program cost-effective.
In Commission Order No. 29462, page 4, states:
Accordingly, Staff believes the Program should be made
available to the maximum number of irrigators possible this
year and to all irrigation customers for the 2005 irrigation
season.
In Case Number IPC-E-08-23, the Company requested approval to offer the
Irrigation Peak Rewards program to all irrigation customers, which the Commission
granted in Order No. 30717.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 15
REQUEST NO. 11: In 2010, what percentage of Irrigation Load Control Program
participants used dispatchable load control devices versus timer based load control
devices? In 2010, what percentage of the enrolled Irrgation Load Control Program
curtailment came from dispatchable load control devices vs. timer based load control
devices?
RESPONSE TO REQUEST NO. 11: In 2010,86.3 percent of Service Locations
participated in the dispatch options and 13.7 percent participated under the Timer
options. The Company estimates that approximately 3 percent of the amount of load
reduction came from timers and that 97 percent came from customers on the dispatch
options.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 16
REQUEST NO. 12: When the Company provides the monthly "Bil Credit" to
participating customers, what percentage of participants have historically chosen to
receive a check in the mail, and how many have chosen to have the credit amount
applied directly to the bilL. As part of your response, please provide the Company's total
annual administrative cost differences associated with each selection.
RESPONSE TO REQUEST NO. 12: Up until 2010, participants did not receive
incentive checks for any option in the program. In the program modifications filed and
approved in 2010 (Commission Order No. 30717), the Commission approved a
modification to the program to require customers under Option 3 to be paid by check. In
2010, Option 3 participants were paid with a check and all other participants received
bil credits through Idaho Power's normal biling system.
Although the payment of incentives via checks may result in slightly higher
administrative costs than paying incentives via a bill credit, this exact analysis has not
been performed. Paying Option 3 incentives by check was proposed to allow the
program managers more time to perform the meter data analysis necessary to
accurately calculate the incentives for the Option 3 participants.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 17
REQUEST NO. 13: On page 2 of the Application, the Company states that it
"enhanced its traditional annual review by conducting an additional study in conjunction
with its 2011 Integrated Resource Plan ("IRP") analysis. This study was conducted in
an effort to ensure that the Program's design is aligned with the resource needs
identified in the IRP." Please provide the full study, along with the executable electronic
copy of the workpapers.
RESPONSE TO REQUEST NO. 13: Idaho Powets traditional analysis has
consisted of estimating the demand reduction associated with the program based on
system load data, actual demand enrolled in the program, realization rates from third-
party and in-house studies, and load research data. This demand reduction estimate
along with actual and forecasted expenses and demand savings were incorporated into
a 20-year cost-effectiveness analysis to determine if the program was cost-effective.
The cost-effectiveness analysis compared the levelized cost per kW of the program with
the levelized cost per kW of a 170 MW simple cycle combustion turbine. The cost-
effectiveness methodology is described in the Technical Appendix of Idaho Powets IRP
and in the Demand-Side Management 2009 Annual Report; Supplement 1: Cost-
effectiveness. In addition, the results of this cost-effectiveness analysis were reported
in the Irrigation Peak Rewards reports and the Demand-Side Management Annual
report filed with the Commission. The Demand-Side Management 2009 Annual Report
and the 2009 IRP can be found at:
http://ww.idahopower.com/AboutUs/RatesRegulatorv/Reports/default.cfm?state=id
In 2010, the Company conducted additional analyses, the results of which are
shown in Exhibit No. 1 of the direct testimony of Peter Pengily. The data that produced
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -18
the chart on page 1 is contained in the Excel workbook, 2010 5 Minute Load Data -
2010 Summer, provided on the enclosed CD. The data used to generate page 2 of
Exhibit No. 1 is provided in the Excel spreadsheet, Forecast Peak day 2011, provided
on the enclosed CD. The data that was used to produce the chart on page 3 of Exhibit
No. 1 is included in the Excel spreadsheet, LoadDurationCurves 2011_2014, provided
on the enclosed CD. The data supporting the chart on page 4 of Exhibit NO.1 is
included in the Excel spreadsheets, 2010 11_15 Load and Resource Balance for DR
Calculations and 2010 11_15 2011 IRP Demand Response Targets, provided on the
enclosed CD. Additionally, the Excel file included on the enclosed CD, 2010 11_16
SCCT vs Demand Response Program Cost Updated, contains a graph used to visualize
how the program compares to a simple cycle combustion peaker on a megawatt-hour
basis.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 19
REQUEST NO. 14: On Exhibit 1, page 2 of Pete Pengily's Testimony, he shows
the Company's "Theoretical 2011 Dispatch of 310 MW of Demand Response." The
Exhibit shows the interruptions being spread over seven hours, as opposed to the four
that are listed in the tariff for individual customers. Please explain how the interruptions
are typically spread into phases throughout an event, and how the interruptions are
managed throughout the season.
RESPONSE TO REQUEST NO. 14: In the past, the Company has tested the
impact of grouping participants for staggered startend times, as can be seen from data
provided in Exhibit No.1, page 1 of Peter Pengily's direct testimony. The schedule
shown in Exhibit No.1, page 1 was typical for 2010. In 2009, it was typical for the
Company to start dispatching as early as 2:30 p.m. with some of the participant groups.
In the future, with the ability to curtail some customers in the 8:00 p.m. to 9:00 p.m.
hour, the Company will start earlier in the day to try to keep the system load flatter as
shown in Exhibit No.1, page 2 of Peter Pengily's direct testimony. However, this abilty
to flatten load with demand response wil be dependent upon the magnitude of the
Company's system peaks. As ilustrated on Exhibit NO.1, demand response of
approximately 300 MW should work well for peaks around 3,500 MW. As can be seen
on page 4 of Exhibit No. 1 of Peter Pengily's direct testimony, the 2011 system peak
under IRP forecasting assumptions is 3,515 MW. The interruptions are managed
throughout the season in accordance with the process described in the Company's
Response to Staffs Production Request NO.7.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 20
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 21
REQUEST NO. 15: On Exhibit 1, page 3 of Pete Pengily's Testimony, he
provides a graph to illustrate the Company's projected need for demand response over
the planning period. Why was the highest 60 hours per year used to determine 306 MW
of potential demand reduction when Exhibit NO.1, page 1 of Pete Pengilly's Testimony,
shows Irrigators interruptions occurring in three phases over 5 total hours (more than an
events maximum of 4 hours per participant)? What would be the result if potential
demand were based on more than 60 hours (e.g.-80 hours) to reflect the event
interruptions being deployed over several phases?
RESPONSE TO REQUEST NO. 15: The Company used the highest 60 hours of
the forecast load duration curves to determine the capabilty of a demand response
program to provide load reduction as specified and targeted in the tariff and the program
literature. The results of using an expanded target of 80 hours in the analysis would
result in a load reduction potential as shown in the table below.
Achievable DR
with 80 Hour
Year Program (MW)
2011 329
2012 227*
2013 379
2014 379
2015 356
2016 382
2017 427
2018 472
2019 465
2020 422
*Based on June 2012 system peak
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 22
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 23
REQUEST NO. 16: On Exhibit 1, page 3 of Pete Pengily's Testimony, he
provides a graph to ilustrate the Company's projected need for demand response over
the planning period under extreme load conditions. Please provide actual 2010 data on
this graph, and explain how including it might change the outcome of your variabilty
analysis and incentive structure?
RESPONSE TO REQUEST NO. 16: The Excel spreadsheet provided on the
enclosed CD, LoadDurationCurves 2010_2014, includes a graphed 2010 actual load
duration curve as well as the load duration curve reconstructed to include demand
response. The Company believes that including data associated with the actual 2010
load duration curves on this graph into the overall analysis would have minimal or no
impact to the variability analysis and incentive structure. The variability analysis is
prospective, as is all IRP resource planning, and uses 95 percentile loads, not actual
loads.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 24
REQUEST NO. 17: When comparing the proposed "Fourth Revised Sheet No.
23-5" to the current "Third Revised Sheet No. 23-5," it appears the Company's proposal
eliminates the opportunity for Dispatchable Option 3 participants to "manually interrupt
electric service to participating irrigation pumps during load control events." However,
under "Program Description" on the "Fourth Revised Sheet No. 23-1," it states "In
limited applications, a select group of eligible Customers wil be permitted to manually
interrupt electric service to participating irrigation pumps during load control events (See
Dispatchable Option 3)." Does the Company's proposal eliminate the opportunity for
Dispatchable Option 3 participants to "manually interrupt electric service to participating
irrigation pumps during load control events"? If so, please explain why this is the
proposal, and how it wil impact customers.
RESPONSE TO REQUEST NO. 17: No. This proposal does not eliminate the
opportunity for Dispatchable Option 3 participants to "manually interrupt electric service
to participating irrigation pumps during load control events." This proposed change in
tariff language was intended to clarify that Option 3 participants could choose any
method they want to turn off pumps during load control events.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 25
REQUEST NO. 18: On Exhibit 1, page 4 of Pete Pengily's Testimony, please
explain why the:
a. "Peak Load" (Column B) drops by 85 MW between 2011 and 2012.
b. "60th Hour Peak Load" (Column C) increases by 18 MW between
2011 and 2012 when the "Peak Load" (Column B) drops over the
same period.
c. "L&R Balance Deficit Position w/o DR Programs" (Column F) drops
by 223 MW between 2011 and 2012.
d. "Operational Target" (Column i) is higher than the "Demand
Response Target" (Column H) in some years and lower in other
years. How is this "Operational Target" determined?
RESPONSE TO REQUEST NO. 18:
a. "Peak Load" in this case is not the typical usage of the term. The "Peak
Load" in column B reflects the system load at the time of the projected maximum peak
capacity deficiency in each year. However, the projected peak hour load in 2012 is
expected to occur in July, which is greater than 2011. The forecasted peak hour loads
in 2011 are from the July peak hour and for 2012, the greatest capacity deficiency
corresponds to peak hour load from June. In preparation of Exhibit NO.1, page 4 of
Peter Pengilly's direct testimony, a footnote to the chart was inadvertently omitted. The
peak load used for analysis in 2012 is the June forecast peak load. The June peak load
was used in the analysis because the Company anticipates the Langley Gulch Power
Plant to be operative by July 2012, which makes the greatest deficit position in the load
and resource balance to be in June 2012 rather than July 2012.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 26
b. Please see the Company's Response to Staffs Production Request 18.a
above.
c. Please see the Company's Response to Staffs Production Request 18.a
above.
d. Through the Operational Target (column i), the Company plans to
maintain a relatively stable level of program participation while at the same time
attempting to achieve as much of the load and resource deficit position as reasonable.
These targets were established using the Company's judgment that a variable payment
structure is better than trying to ramp program participation up and down with the actual
resource need.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 27
REQUEST NO. 19: On Exhibit 1, page 3 of Pete Pengily's Testimony, please
explain why the peak load hour in 2012 is greater than in 2011, when Exhibit 1, page 4
of Pete Pengily's Testimony shows "Peak Load" in 2012 being less than 2011.
RESPONSE TO REQUEST NO. 19: Please see the Company's Response to
Staffs Production Request No. 18 above.
In preparation of Exhibit NO.1, page 4 of Peter Pengily's direct testimony, a
footnote to the graph was inadvertently omitted. The peak load used for analysis in
2012 is the June forecasted peak load. The June peak load was used in the analysis
because the Company anticipates the Langley Gulch Power Plant to be operative by
July 2012, which makes the greatest deficit position in the load and resource balance to
be in June 2012 rather than July 2012.
The response to this Request was prepared by Peter Pengily, Customer
Research & Analysis Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
DATED at Boise, Idaho, this 31st day of January 2011.
~f1~tkiSD~ORDS OM
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 28
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 31st day of January 2011 I served a true and
correct copy of IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER
COMPANY upon the following named parties by the method indicated below, and
addressed to the following:
Commission Staff
Weldon B. Stutzman
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
Idaho Irrigation Pumpers
Association, Inc.
Eric L. Olsen
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
201 East Center
P.O. Box 1391
Pocatello, Idaho 83204-1391
Anthony Yankel
Yankel & Associates, Inc.
29814 Lake Road
Bay Vilage, Ohio 44140
-- Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email Weldon.StutzmanCãpuc.idaho.gov
Hand Delivered
-lU.S. Mail
_ Overnight Mail
FAX
-- Email eloCãracinelaw.net
Hand Delivered
-lU.S. Mail
_ Overnight Mail
FAX
-- Email tony~yankel.net
~~.?l~Lisa D. Nordstr
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 29