20070904PAC to IIPA 4-1 to 4-16.pdf

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August 31 , 2007
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Eric Olsen
Idaho Irrigation Pumpers Assoc
Racine, Olsen, Nye, Budge & Bailey
201 East Center
Pocatello, ID 83204
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RE:PAC-07-
IIPA Set 4 (1-16)
Please find enclosed Rocky Mountain Power s Responses to IIPA 4th Set Data Requests
1 - 4.16. Provided on the enclosed CD are Attachments lIP A 4.3 and 4.
If you have any questions, please feel free to call me at [phone].
Sincerely,
Brian Dickman, Manager
Regulation
IEJP
Enclosures
Cc:Tony YankellIIPA
Jean JewelllIPUC
Randall C. Budge/Monsanto
James R. SmithIMonsanto
Maurice Brubaker/Monsanto
Richard Anderson/Energy Strategies
Conley Ward/Agrium
Dennis Peseaul Agrium
Brad Purdy/CAP AI
Timothy Shurtz
P AC-07-05/Rocky Mountain Power
August 31 2007
lIP A 4th Set Data Request 4.1
liP A Data Request 4.
Please provide electronically a listing of the most recent data available of all
dates, times, and expected magnitude of all dispatched curtailments when Idaho
irrigation load was curtailed under the pilot program of Schedule 72A.
Response to liP A Data Request 4.
2007 Idaho Irrigation Load Management Program Schedule 72A
Dispatch Date Dispatch Time Estimated Magnitude
(megawatts)
Jul-3:30p - 7:00p
12-Jul-4:00p - 7:00p
16-Jul-3:30p - 7:00p
19-Jul-4:00p - 7:00p
23-Jul-4:00p - 7:00p
26-Jul-4:00p - 7:00p
3 1-Jul-4:00p - 7:00p
Total July
Aug-4:00p - 7:00p
Aug-4:00p - 7:00p
10-Aug-4:00p - 7:00p
13-Aug-4:00p - 7:00p
15-Aug-4:00p - 7:00p
17-Aug-4:00p - 7:00p
Total August
(to date)
Estimation methodology:
The estimate of curtailment magnitude for Idaho s 2007 Schedule 72A program is
based on the nameplate rating of the pumping equipment participating in the
Schedule 72A pilot control program.
(This response was prepared under the direction of Jeff W. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
PAC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I, near the bottom of page ES-
10 there is a reference to the fact that participant incentives are currently capped
at approximately 50% of "incremental measure costs" of Class 2 DSM resources.
Please explain what "incremental measure costs" are and give an example.
If "incremental measure costs" are not an appropriate term, please explain
what the 50% is related to.
What is the basis for the 50% cap?
Is there a related cap applied to Class 1 or 3 DSM resources? Please
explain the relationship between such a cap for Class 1 and 3 resources
compared to Class 2.
Response to liP A Data Request 4.
Incremental measure costs" refers to investments required to be made by
customers in order to participate in Class 2 DSM programs. Customer
incentives for Class 2 DSM programs are typically measured as a
percentage of out of pocket customer costs up to a cap. The Idaho
Irrigation Energy Savers program uses the 50% cap explicitly in the
incentive calculation (see Idaho Schedule 155.4).
The term is appropriate as used in the report.
Energy efficiency programs are designed to provide incentives for the
purchase of more energy efficient equipment not to pay customers for
replacing equipment. The equipment also needs to deliver energy savings
over time. For these reasons, most programs pay a percentage (less than
100%) of the incremental costs so the customer is invested in equipment
upgrades and efficient operation over time. The 50% cap is explicitly
incorporated into several incentive formulas in the company s energy
efficiency programs and is the basis for setting the incentive levels in other
programs. Other utilities and program administrators use a similar
percentage cost cap in many of their program designs. For these reasons
50% was used in this study in the assessment of the expected achievable
potential for Class 2 resources.
In the case of Class 1 and 3 resources, customers typically are not required
to make investments in equipment to participate in demand-side resource
programs. As a result, customer incentives are tied to metrics such as
kilowatts available for control rather than as a percentage of out of pocket
customer costs up to a cap, as in the case for Class 2 programs. In
designing incentive structures for Class 1 and Class 3 programs, programs
P AC- E-07 -05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.2
typically are required to pay an incentive each time (per month or per
year) the capacity resource is made available for control or controlled.
Unlike Class 1 and 3 resources, energy efficiency programs typically pay
an incentive once and the energy efficiency resources are realized over
time. These are some of the reasons that incentive design considerations
(including the use of percent of customer costs) differ between these
resource types.
(This response was prepared under the direction of Jeff W. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
PAC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 12 that PacifiCorp
provided "2000-2005 hourly profiles by rate class . Please provide an electronic
copy of this information.
Response to liP A Data Request 4.
Attachment lIP A 4.3 contains the referenced data "2000-2005 hourly profiles by
rate class." The files contain complete data for some states (annual periods as
noted in individual state files), single year data for others and was lacking
available California data at the time the profiles were created. In all the cases
except California, the most recent year s data for each state and rate schedule
were used in the development of hourly system load profiles. In the case of
California, Oregon s load profiles by customer class were used. Single year data
was used (as opposed to multiple year averages) in order to retain the peak
characteristics of the load shapes for Class 1 and Class 3 capacity focused
products.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
IDAHO
P AC-O7-
ROCKY MOUNTAIN POWER
lIP A DATA REQUEST SET 4 (1-16)
TT A CHMENT lIP A 4.
ON THE ENCLOSED CD
PAC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.4
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 12 that PacifiCorp
provided cost information regarding "PacifiCorp program experience . Please
provide an electronic copy of this information.
Response to liP A Data Request 4.4
The company s program experience, costs and program performance information
were collected over time through a series of verbal exchanges during the study
development. As such, there is no specific electronic record to provide. The
company s experiences were used to help challenge the reasonableness of other
utility program best practice information gathered in the development of program
assumptions. To the extent the company s data was captured in the report, it is
provided through its documentation in Volume II, Appendix B-1 in the "Sources
or Assumptions" references.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
P AC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 12 that PacifiCorp
provided cost information regarding "the system hourly shape for 2006, Figure
3... "
a. Was this "system" load data for Retail only, or did it include Retail and
Wholesale Sales?b. If this was for Retail load only, please provide an electronic copy of this
load data, specifying date, hour, and load.
(c) If this was for Retail plus Wholesale sales, please provide an electronic copy
of this load data broken out between Retail and Wholesale sales specifying date
hour, and load.
Response to liP A Data Request 4.
The load data was Retail only.
The actual system hourly data for 2006 had not been compiled at the time
the report was being completed. Therefore, the report used 2005 actual
data modifying the 2006 sales data to reflect the expected 2006 system
hourly load profile. Refer to Attachment lIP A 4.5 for the 2006 Sales with
2005 System Shape as the referenced data.
See lIP A 4-
(This response was prepared under the direction of Jeff W. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
IDAHO
P AC-O7-
ROCKY MOUNTAIN POWER
lIP A DATA REQUEST SET 4 (1-16)
ATTACHMENT lIP A 4.
ON THE EN CLOSED CD
P AC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 13 there is a statement at
the bottom of the page that loads based on the highest 40 hours for the winter and
summer were estimated and then spread over end-use hourly load profiles and
calibrated. Please provide a detailed example of what was done, based upon the
Idaho Irrigation load.
Response to liP A Data Request 4.
No calibration of irrigation loads was necessary given irrigation loads are
comprised of, for the most part, a single end use.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
PAC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 17 there is a statement
that Rocky Mountain Power s avoided cost of capacity is $98.
a. Is this value of$98 based on a "kW-year" basis? Please explain what
these units represent.b. 'Is this capacity value only related to the peak hour of the year, the highest
40 hours of the year, the peak hour of each month, etc.
Please provide all calculations and studies used to develop this value of$98.
Response to liP A Data Request 4.
In section 6, Estimating Economic Potential , the reference to the
company s estimated avoided cost of capacity of $98 for Rocky Mountain
Power was based on dollars per kilowatt per year. It represents an estimate
of the value used to set the upper boundary for screening capacity
resources for their cost-effectiveness within the study.
The capacity represents the company s coincident peak loads. Coincident
peak loads are derived by forecasting and then aligning the hourly
maximum loads each month across the entire system. Coincident peak is
the highest load hour each month across the entire system.
The $98 value used to screen load management demand-side resources in
Rocky Mountain Power s service territory was derived from proxy
modeling of load management resources within the company s 2007
Integrated Resource Plan. For the development of that plan, the company
commissioned a smaller potential assessment and costing of five load
management program concepts into supply curve formats for comparative
modeling against supply-side resource alternatives. The five program
concepts developed and modeled were: (1) a fully dispatchable winter
resource, (2) a fully dispatchable summer resource, (3) a fully dispatchable
large commercial and industrial resource, (4) a scheduled firm irrigation
resource, and (5) a thermal energy storage resource. In Rocky Mountain
Power s service territory, the model selected all available fully
dispatchable summer resources (at $58/kw/yr), all available fully
dispatchable large commercial and industrial resources (at $82/kw/yr) and
all scheduled firm irrigation resources (at $27/kw/yr). Based on the
modeling results the company determined the value of the resources to be
greater than $82/kw/yr (based on the model selecting the fully
dispatchable large commercial and industrial resources) but less than
$119/kw/yr (the cost for the thermal energy storage resources that weren
P AC- E-07 -05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
selected). The $98/kw/yr was selected as the estimated value to Rocky
Mountain Power, ignoring unique resource characteristics (such as
dispatchability, hours, etc.), after which load management resources
become uneconomic in relation to other resource alternatives. No
additional analysis was done in arriving at the $98/kw/yr figure. The
company s 2007 Integrated Resource Plan is available in an electronic
format at http://www.pacificorp.comlNavigation/Navigation23807.html.
The proxy supply curve study conducted for the plan is provided in
Appendix B of that document.
(This response was prepared under the direction of Jeff W. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
P AC-07-05/Rocky Mountain Power
August 31 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 22 the levelized cost for
irrigation in RMP is listed at $47.
a. Please provide a breakdown of the dollars associated with each component
that makes up this value (i.e. installation, administration, incentives, etc.
b. If this cost is based upon both Schedule 72 and 72A, please provide a
breakdown of the dollars associated with each component that makes up this $47
value based upon Schedule 72 and 72A separately (i.e. installation
administration, incentives, etc.
Response to liP A Data Request 4.
a. The $/kw/yr value was derived using the achievable resource potential
(providing program size) and the standard program cost assumptions
(referenced below) to derive a total program cost. This cost was then
levelized over a 20-year planning period to identify the resource value. As
such, a breakdown of the cost components beyond that provided in Volume II
Appendix B-1 of the report (Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option) is not available. The resource cost
assumptions are: Overhead: First Cost - $400 000, Admin Cost adder 15%,
Technology and installation cost - $100 000, Incentive annual cost/kW $20
Marketing Cost/new participant $20, Ongoing maintenance and
communication / kW $10. For a complete breakdown of costs see Table B-1 0
page B-, Volume II.
b. The costs do not assume a particular program however they do draw from
estimated costs of several programs such as the company s Idaho Schedule 72
and 72A as well as Idaho Power s program. The $47 is meant to represent a
proxy for program costs, actual implementation costs may vary with factors
such as size of program, average pump size, and pump configurations
impacting those costs.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
P AC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 22 the levelized cost for
Residential DLC AC in RMP is listed at $93. Please provide a breakdown of the
dollars associated with each component that makes up this value (i.e. installation
administration, incentives, etc.
Response to liP A Data Request 4.
The $/kw/yr value was derived using the achievable resource potential (providing
program size) and the standard program cost assumptions (referenced below) to
derive a total program cost. This cost was then levelized over a 20-year planning
period to identify the resource value. As such, a breakdown of the cost
components beyond that provided in Volume II, Appendix B-1 of the report
(Capacity-Focused Resource Materials: Detailed Assumptions by Program
Option) is not available. The resource cost assumptions are: Overhead: First Cost
- $400 000, Admin Cost adder 15%, Technology and installation cost - $175
Incentive annual cost $20 for residential and 40$ for small commercial, Marketing
Cost/new participant $25, communication cost per customer $10. For a complete
breakdown of costs and other assumptions see Table B-, page B-, Volume II.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
P AC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 24 the levelized cost for
Residential TOU in RMP is listed at $166.
a. Please provide a breakdown of the dollars associated with each component
that makes up this value (i.e. installation, administration, incentives, etc.b. Ifthis price reflects the cost of Schedule 36 in Idaho, what adjustments
should be made to get these costs under the $98 kW-year figure in the study?c. The Company is proposing to give Schedule 36 the "standard" rate
increase in this case. This suggests that the Company does not feel that the rate-
of-return for this customer group is that far from normal. Given this, on what
basis does the July 11
th report come up with such different conclusions?d. If the Company were going to change Schedule 36 to be more in line with
the July 11th study recommendation, what rates (presumably a three tiered rate)
would it suggest?
Response to liP A Data Request 4.
a. The $/kw/yr value was derived using the achievable resource potential
(providing program size) and the standard program cost assumptions
(referenced below) to derive a total program cost. This cost was then
levelized over a 20-year planning period to identify the resource value.
such, a breakdown of the cost components beyond that provided in Volume II
Appendix B-1 of the report (Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option) is not available. The resource cost
assumptions are: Overhead: First Cost - $400 000, Admin Cost adder 15%
Technology and installation cost - $100, Marketing Cost/new participant $25.
For a complete breakdown of costs and other assumptions see Table B-
page B-, Volume II.
b. The data and assumptions concerning costs and other technical inputs were
based on data from TOU programs offered by the company as well as other
utilities. The price therefore represents a blend of costs rather than one
particular utility program.
c. The price increase requested for Schedule 36 is derived from the results of the
company s class cost of service study filed in this case. As noted in the
company s response to part "b" above, the data and assumptions concerning
costs and other technical inputs to the July 11 , 2007, study were based on data
from TOU programs offered by the company as well as other utilities. The
price therefore represents a blend of costs rather than one particular utility
program.
P AC- E-07 -05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.10
d. The company has not performed the requested analysis.
(This response was prepared under the direction of Jeff W. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
P AC- E-07 -05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 36 it states that 100 MW
of irrigation load has been contracted for load management, but "less than half are
available at any time due to the alternating schedules of program participants." It
is also stated that: "only 75% of the load will be available. Please supply in
electronic format, any data upon which these statements are based.
Response to liP A Data Request 4.
With respect to that report, in Volume II page B-, the assumptions regarding
event participation are provided. The report assumes that of the program
participants, 50% of participating loads will elect a scheduled firm control option
(similar to Idaho s Schedule 72) and 50% will elect a dispatchable control option
(similar to Idaho s Schedule 72A). Under these assumptions during any given
day, 50% of the scheduled firm participant loads would be curtailed and, upon
dispatch, 100% of the dispatchable loads would be available; thus arriving at the
assumption that 75% of the loads participating are curtailed during an event.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
PAC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume I page 46 it states that newer
TOU programs tend to have a differential of greater than 10 cents /kWh.
PacifiCorp were to revise its Schedule 36 in order to be compatible with these
newer TOU programs, what rates would be appropriate for winter and summer
usage?
Response to liP A Data Request 4.
The company has not performed the requested analysis.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
PAC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume II page B-13 there is a listing of
information for the Irrigation demand side management program.
a. How do these costs and assumptions compare with those recently
experienced regarding the Company s experience with Schedule 72 in Idaho?b. How do these costs and assumptions compare with those recently
experienced regarding the Company s experience with Schedule 72A in Idaho?c. What is contained in the $10 figure for "Incentives (annual costs per
participating kW)?
Response to liP A Data Request 4.
a. As noted in Volume II Page B-13 of the study s assumptions, they are similar
however represent a composite of programs (see references to Idaho Power
and PacifiCorp program similarities and differences in the Sources or
Assumption column). They are slightly higher in some areas, such as the
technology costs and communications portion of ongoing maintenance and
communications, than those typically realized with Schedule 72 in Idaho.
These costs are more representative of anticipated Schedule 72A in Idaho or
technology that as employed provides greater control flexibility and network
reliability. The remaining assumptions and costs are similar to the company
Schedule 72 program and Idaho Power s irrigation load management program
except where noted in the Sources and Assumptions column.
b. As noted in the company s response to part "" the study s costs and
assumptions are a composite of program costs and assumptions however are
more closely in alignment, in regards to the technology and communication
costs, with the equipment employed under the company s Schedule 72A in
Idaho. They assume that similar control equipment as that deployed in the
company s Schedule 72A dispatchable pilot program would be utilized by
both control options (Schedule 72 and Schedule 72A) in the future to improve
control functionality and network reliability.
c. The $10 figure labeled "Incentives (annual cost per participation k W)" is mis-
labeled. It should read "Ongoing Maintenance and Communications." It
represents the annual costs to maintain installations including hardware
recursive communications and field labor costs.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
P AC- E-07 -05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
PAC-07-05/Rocky Mountain Power
August 31 , 2007
IIPA 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. With respect to that report, in Volume II page B-24 there is a listing of
information for the Residential TOU program.
a. The incremental cost of meters is listed as $100. What is the maximum load a
meter of this cost is designed to carry?
b. Will this meter handle 3 phase power?c. Why does "this analysis assume revenue neutrality for the utility" when
some customers will accrue bill savings?d. How should the rates for Schedule 36 be designed in order to be revenue
neutral for the Company and show a differential of 10 cents or more per kWh?
Response to liP A Data Request 4.
The $100 incremental cost was based on the average cost differential
between a standard residential meter and a residential time of use meter
with an assumed amperage rating of200.
The price difference between a single and three phase 200 amperage rated
meter is immaterial and the study made no assumption as to a single or
three phase meter when calculating incremental costs.
This analysis assumes revenue neutrality for the utility because, during the
rate making process of each schedule, there is a targeted amount of
revenue that proposed rates are to collect; and while it is true some
customers may accrue bill savings from these proposed rates, other
customers may receive bill increases based on individual usage.
The company has not performed the requested analysis.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response.
PAC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. In addition to the two volume report, there was some supplemental
material provided. As a part of that material there was a Figure 29 that related
an Irrigation forecast for Idaho between 2006 and 2027. It appears that the 2006
value for Idaho Irrigators at generation was less than 72 aMW. What was the
actual value for 2006? What loss factor was assumed?
Response to liP A Data Request 4.
The actual value for 2006 was 66.25 aMW with an assumed loss factor of7.1% to
arrive at a grossed up value of 70.95 aMW.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )
PAC-07-05/Rocky Mountain Power
August 31 , 2007
lIP A 4th Set Data Request 4.
liP A Data Request 4.
On July 11 , 2007 there was a report issued by PacifiCorp assessing demand side
resources. In addition to the two volume report, there was some supplemental
material provided. As a part of that material there was a Figure 42 that related to
Idaho Single Family Heating load. Is this data for Schedule 1 , 36, or both?
Response to liP A Data Request 4.
The specific end use shapes used in the study, such at the Idaho single family
heating load, were derived from building simulations, not meter data, and
therefore are representations of the expected load shapes.
(This response was prepared under the direction of JeffW. Bumgarner, who is
also the recordholder. It has not been determined who will sponsor this response
at hearing. Please contact Brian Dickman at 801-220-4975 to discuss this
response. )