20110809IPC to DOE (3) 1-35.pdf

isIDA~POR~
An IDACORP Company
JASON B. WILLIAMS
Corporate Counsel
iwilliams~idahopower.com
August 9, 2011
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilties Commission
472 West Washington Street
Boise, Idaho 83720
Re: Case No. IPC-E-11-08
General Rate Case
Dear Ms. Jewell:
Enclosed for filng are an original and one (1) copy of Idaho Power Company's
Response to the U.S. DOE's Third Interrogatories and Production Requests to Idaho
Power Company in the above matter. In addition, enclosed for filng are an original and
one (1) copy of Idaho Power Company's Confidential Response to the U.S. DOE's Third
Interrogatories and Production Requests to Idaho Power Company in the above matter.
Also enclosed are three (3) copies of a non-confidential disk and three (3) copies of
a confidential disk containing information being produced in response to the U.S. DOE's
third request.
Please handle the enclosed confidential information in accordance with the
Protective Agreement executed in this matter.
Very truly youra,--~
~; B. Wiliams
JBW:csb
Enclosures
1221 W. Idaho St. (83702)
P.O. Box 70
Boise, 10 83707
LISA D. NORDSTROM (ISB No. 5733)
DONOVAN E. WALKER (ISB No. 5921)
JASON B. WILLIAMS
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
InordstromCãidahopower.com
dwalkerCãidahopower.com
jwilliamsCãidahopower.com
RECEIVED
iOll AUG -9 PM It: 06
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC )SERVICE IN IDAHO. )
)
)
)
)
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY'S
RESPONSE TO THE U.S. DOE'S
THIRD INTERROGATORIES AND
PRODUCTION REQUESTS TO
IDAHO POWER COMPANY
COMES NOW, Idaho Power Company ("Idaho Powet' or "Company"), and in
response to the U.S. Department of Energy's ("DOE") Third Interrogatories and
Production Requests to Idaho Power Company dated July 19, 2011, herewith submits
the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 1
REQUEST NO. 3.1: Please provide the document referred to by Mr. Larkin on
page 24, 9-13, and that is included in his workpapers, in native format (e.g., Adobe,
Word).
RESPONSE TO REQUEST NO. 3.1: Please see the Word document provided
on the non-confidential CD.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 2
REQUEST NO. 3-2: Please provide Idaho Powets "estimated demand
reductions achieved through the respective DR programs" that were used to derive
system coincident demand factors in this case, both by program (Le., Irrigation Peak
Rewards, AlC Cool Credit, and FlexPeak Management) and in total, and on an hourly
basis to the extent these reductions were estimated on an hourly basis, in native format
(e.g., Excel) with all links and formulas intact (if applicable). (M. Larkin, p. 23, 22-25.)
Please also provide the derivation of the requested demand reduction information.
RESPONSE TO REQUEST NO. 3-2: The demand reduction amounts that were
used to derive the system coincident demand factors in this case were based on 2010
estimated results. Please see the Excel spreadsheet, 2006_through_201 O.xlsx,
provided on the non-confidential CD with the load estimated demand reductions
achieved through the respective demand response programs by program and hour for
2006 through 2010.
The demand reductions realized from the AlC Cool Credit, FlexPeak
Management, and Irrigation Peak Rewards programs are derived from several sources.
The data associated with the calculations of these hourly demand reductions are
voluminous. Therefore, Idaho Power has included examples of the derivation of
estimated demand reductions for each program for 2010.
A1C Cool Credit
For AlC Cool Credit, the Company utilzes an average realization rate for each
customer as determined by a third-party evaluation conducted by Summit Blue
Consulting, LLC, in 2006. The evaluation is provided on the non-confidential CD as file
SBC_IPCo_ A C_2006_FinaLReport. pdf. As shown on pages 2-3 of the report, at 50
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 3
percent cycling, the program had a realized demand reduction of 1.12 kilowatts ("kW")
per participant at the meter leveL. The demand reduction is then grossed up by 13
percent to account for on-peak line loss. Additionally, the Company has load research
data on some of the participants, which varies from year to year, that is used to monitor
the load reduction. The table below ilustrates how the demand reduction was
calculated for the program for June 29, 2010.
Number of Est. Demand Est. Demand
Participants Reduction (at Meter)Reduction (at
Generation)
4:00 - 5:00 pm 29,464 33,000 kW 37,290 kW
5:00 - 6:00 pm 29,464 33,000 kW 37,290 kW
6:00 - 7:00 pm 29,464 33,000 kW 37,290 kW
FlexPeak Management
For FlexPeak Management, the third-party aggregator, EnerNOC, Inc.
("EnerNOC"), and Idaho Power receive five minute interval meter data for each program
participant. At the end of the curtailment season, EnerNOC and Idaho Power analyze
the load data and determine the amount of load reduction realized based on the
baseline methodology determined by the Company's contract with EnerNOC. For the
demand reduction calculations for 2010, please see the Excel file,
20 1 O_FlexPeak_Performance.xlsx, provided on the confidential CD. The confidential
CD wil be provided to those parties that have executed the Protective Agreement in this
docket. The "Participation by Class" tab shows the demand reduction by rate class for
each hour on each event day. The "Performance by Customet' tab shows the demand
reduction of each customer for each hour on each event day. The "Rate Look Up" tab
identifies the rate class of each customer.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 4
Irrigation Peak Rewards
For Irrigation Peak Rewards, the Company computes a realization rate for each
two week period when the program is offered since irrigation load varies throughout the
season. This methodology was originally introduced in a program evaluation conducted
by Summit Blue Consulting, LLC, in 2004 and replicated by the Company and reported
to the Idaho Public Utilities Commission in 2007, 2008, and 2009. A copy of the most
current report with its realization rate assumptions can be found on page 20 of the 2009
Irrigation Peak Rewards Program Report, provided on the non-confidential CD as file
Irrigation_Peak_FinaLReport.pdf. Also for the Irrigation Peak Rewards program, the
Company has interval meter data on all of the Dispatchable Option 3 (at least 1,000
cumulative horsepower) participants and load research data on some of the
participants, which varies from year to year because of crop rotation and program
participation.
The estimate of aggregate load reduction is also compared to the five minute
system load data on a demand response day and compared to a non-demand response
day with similar temperatures and a similar load shape to determine if the aggregation
of the individual program load reduction estimates is reasonable.
For the demand reduction ,calculations for July 16, 2010, please see the Excel
file, 20101rrigatPeakRewardsPerform.xlsx, provided on the confidential CD. The
confidential CD wil be provided to those parties that have executed the Protective
Agreement in this docket. The "July 16, 2010" tab shows the demand reduction by
Dispatch Group for each hour on July 16. The "Performance by Customet' tab shows
the realized demand reduction of each customer. The "Performance by Dispatch
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 5
Group" tab summarizes the data from the "Performance by Customet' tab and feeds in
the "July 16, 2010" tab. Finally, the "Load Reduction" tab shows the potential demand
reduction for each day as well as the estimated reduction achieved on event days. A
number of descriptive comments have been included in this workbook to assist in the
transparency of this process.
The response to this Request was prepared by Pete Pengily, Customer
Research & Analysis Leader, Idaho Power Company, and Mary Graesch, Load
Research & Forecast Leader, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 6
REQUEST NO. 3-3: Please provide Idaho Powets estimated demand
reductions by DR program and in total for the years 2006 through 2010, and on an
hourly basis to the extent these reductions were estimated on an hourly basis, in native
format (e.g., Excel) with all links and formulas intact (if applicable). Please also provide
the derivation of the requested demand reduction information.
RESPONSE TO REQUEST NO. 3-3: Please see the Company's response to
the DOE's Request No. 3-2.
The response to this Request was prepared by Pete Pengily, Customer
Research & Analysis Leader, Idaho Power Company, and Mary Graesch, Load
Research Leader, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 7
REQUEST NO. 3.4: Please provide Idaho Powets "historical hourly system
loads" and "(t)he resulting load shape" that were used to derive system coincident
demand factors in this case, on an hourly basis in native format (e.g., Excel) with all
links and formulas intact (if applicable). (M. Larkin, p. 23, 22-25.)
RESPONSE TO REQUEST NO. 3.4: As described in the Direct Testimony of
Company witness Matthew T. Larkin, hourly system loads were adjusted to find the hour
that the system peak would have occurred in each month had no demand response
programs been utilized. The load was adjusted by adding back the estimated demand
response program reductions at the generation level to the original load on an hourly
basis. These adjusted loads were used to determine the demand factors utilzed in this
case. Please see the Excel file, AdjustedSystemLoad.xlsx, containing adjusted hourly
loads for the 2010 historical year provided on the non-confidential CD.
The response to this Request was prepared by Mary Graesch, Load Research &
Forecast Leader, Idaho Power Company, in consultation with Matthew T. Larkin,
Regulatory Analyst, Idaho Power Company, and Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 8
REQUEST NO. 3-5: Please provide all workpapers that show how "(t)he
adjusted data was then used to determine the hour that the system peak would have
occurred absent DR programs" in native format (e.g., Excel) with all links and formulas
intact (if applicable). (M. Larkin, p. 24, 3-7.)
RESPONSE TO REQUEST NO. 3-5: Please see the Company's response to
the DOE's Request No. 3-4.
The response to this Request was prepared by Mary Graesch, Load Research &
Forecast Leader, Idaho Power Company, in consultation with Matthew T. Larkin,
Regulatory Analyst, Idaho Power Company, and Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 9
REQUEST NO. 3-6: Please provide all workpapers that show how "system
coincident demand factors were calculated according to the adjusted peak hour and
historical usage data" in native format (e.g., Excel) with all links and formulas intact (if
applicable), and please include the referenced historical usage data. (M. Larkin, p. 24,
3-7.)
RESPONSE TO REQUEST NO. 3-6: System coincident demand factors for
sampled rate classes are determined by excluding demand response program
participants from the sample. The system coincident demands are based on the
adjusted system peak's date and time. Please see the Excel file provided on the non-
confidential CD (2010MPUFacts(R01,07,09S,20)ParptsRmvdAdjPeak.xlsx) for these
factors.
For 100 percent sampled rate classes and special contract customers, the
system coincident demands are also based on the adjusted system peak's date and
time. In this case, since all demand response is realized in the 100 percent sampled
load, the demand response program reductions for each rate class are added back to
the peak before calculating the system coincident demand factors in order to represent
the no-demand response scenario. Please see the Excel files provided on the
confidential CD (2010_100%Samp_Facts_(Specials)_AdjPeak.xlsx and
20101 00%SampFacts(R09P, 09T, 19P, 19S, 19T)AdjPk.xlsx).Because these files
contain customer-specific load research data, they are considered confidentiaL. The
confidential attachments wil be provided on a confidential CD to those parties that have
executed the Protective Agreement.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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For lighting rate schedules, the adjusted peak date and time are used for
determining the system coincident demand factors. Please see the Excel file,
LightingFactors_ SunriseSunset20032013.xls, provided on the non-confidential CD.
For Idaho Rate 32, Hoku Materials, Inc., demand factors for the test year are
based on contract specifications using the adjusted peak to identify the half-month
where the peak occurred. This is used for calculations in months where the contract
demand differs between the first half and second half of the month. System coincident
demand factors are based on the assumed 90 percent load factor from the contract and
group coincident demand factors are assumed to be half way between the system
coincident factor and 1.0. The derivation of these factors is detailed on Excel file
1032_ ContracL GCOSCOFactors_Blk1 Blk2.xlsx. This Excel file contains confidential
information and wil be provided on a confidential CD to those parties that have
executed the Protective Agreement.
The response to this Request was prepared by Mary Graesch, Load Research &
Forecast Leader, Idaho Power Company, in consultation with Matthew T. Larkin,
Regulatory Analyst, Idaho Power Company, and Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 11
REQUEST NO. 3-7: Please provide all workpapers that show how "these factors
were applied to forecast average demand to derive coincident peak demands by rate
class for each month of the test period" in native format (e.g., Excel) with all links and
formulas intact (if applicable), and please include the referenced forecast average
demand. (M. Larkin, p. 24, 7-9.)
RESPONSE TO REQUEST NO. 3-7: The application of the factors to forecast
average demand was provided on the "Worksheet" tab of Attachment 46 provided in the
Company's response to the Idaho Irrigation Pumpers Association Inc.'s ("IIPA") Data
Request NO.5.
The response to this Request was prepared by Mary Graesch, Load Research &
Forecast Leader, Idaho Power Company, in consultation with Matthew T. Larkin,
Regulatory Analyst, Idaho Power Company, and Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 12
REQUEST NO. 3-8: Please provide the document referred to by Mr. Larkin on
page 24,22-23 in native format (e.g., Adobe, Word).
RESPONSE TO REQUEST NO. 3-8: Please see the document provided on the
confidential CD. Since this document is confidential, it is being provided to those parties
that have executed the Protective Agreement in this docket.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY -13
REQUEST NO. 3-9: Per Mr. Larkin, page 19, 17-20, "the Company used 2010
load research data to derive the coincident demand values used in the cost-of-service
study prepared in this proceeding."
(a) Please provide the referenced 2010 load research data in native format
(e.g., Excel) with all links and formulas intact (if applicable).
(b) Please provide all hourly class load shapes Idaho Power has developed
from its 2010 load research data in native format (e.g., Excel) with all links and formulas
intact (if applicable).
RESPONSE TO REQUEST NO. 3-9:
(a) Please see the Company's response to the DOE's Request No. 3-6.
(b) Hourly class load shapes derived from 2010 load research data are
provided in the Excel files with "AVGHRDEM" and the rate class identifier in the file
name on the non-confidential CD. Please note several attachments contain customer-
specific load research data and are therefore confidentiaL. The confidential attachments
wil be provided on a confidential CD to those parties that have executed the Protective
Agreement in this docket.
The response to this Request was prepared by Mary Graesch, Load Research &
Forecast Leader, Idaho Power Company, in consultation with Matthew T. Larkin,
Regulatory Analyst, Idaho Power Company, and Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 14
REQUEST NO. 3-10: Mr. Tatum explains his responsibilities to include
overseeing the Company's cost-of-service activities, including marginal cost studies. (T.
Tatum, p. 3, 3-7.) Please respond to the following information requests related to
generation capacity marginal costs.
(a) Please provide the inputs and calculations currently used by Idaho Power
to calculate generation capacity marginal cost in native format (e.g., Excel) with all links
and formulas intact (if applicable). Please explain Idaho Powets rationale for
calculating generation capacity marginal cost in this manner.
(b) Please provide the inputs and calculations currently used by Idaho Power
to seasonalize generation capacity marginal cost in native format (e.g., Excel) with all
links and formulas intact (if applicable). Please explain Idaho Powets rationale for
seasonalizing generation capacity marginal cost in this manner.
(c) Please explain how Idaho Power utilizes generation capacity marginal
costs in the normal course of its business (e.g., rate design studies, demand side
management studies, contract negotiations), and please explain why Idaho Power
utilzes those marginal cost estimates in the manner that it does.
(d) To what extent have Idaho Powets generation capacity marginal costs
varied on both an annual and seasonal basis over the period from and including Idaho
Power's 2002 Integrated Resource Plan through the present? What has been the
primary factor(s) that has caused Idaho Powets annual generation capacity marginal
cost to vary over this time period? What has been the primary factor( s) that has caused
Idaho Power's seasonalized generation capacity marginal costs to vary over this time
period?
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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(e) To what extent does Idaho Power believe its generation capacity marginal
costs wil vary on both an annual and seasonal basis over the period from and including
Idaho Power's 2011 Integrated Resource Plan through 2015? What does Idaho Power
believe will be the primary factor(s) that wil cause Idaho Powets annual generation
capacity marginal cost to vary over this time period? What does Idaho Power believe
wil be the primary factor(s) that wil cause Idaho Powets seasonalized generation
capacity marginal costs to vary over this time period?
RESPONSE TO REQUEST NO. 3-10:
(a) The Excel file provided on the non-confidential CD contains the generation
capacity marginal cost in its native format.
The 2011 marginal cost analysis was prepared according to concept and design
specifications of the National Economic Research Associates, Inc. ("NERA") marginal
cost modeL. The NERA model is constantly being refined but the basic concepts and
methods have remained the same since Idaho Power began using this method. The
study identifies the long-run marginal cost of providing electric service to new load on
Idaho Powets system.
Generation capacity marginal costs are based upon the levelized cost of a
simple-cycle combustion turbine from Idaho Powets 2009 Integrated Resource Plan
("IRP"). The peaking resource selected from the resource portolio to quantify the
marginal generation capacity cost is the Danskin CT1 combustion turbine. This
resource is used as the marginal cost basis because it represents the latest peaking
resource addition to the Company's rate base. Additional detail regarding the derivation
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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of the generation capacity marginal costs can be found on page 60 of Company witness
Matthew T. Larkin's workpapers.
(b) The Excel file provided on the non-confidential CD contains the
seasonalization of the generation capacity marginal cost in its native format.
The following description is included on page 60 of Mr. Larkin's workpapers:
The seasonalization of generation capacity marginal costs is based
on information from the 2009 IRP. The Company plans new
peaking generation capacity based on monthly peak hour load
surplus/deficiency data, assuming 90th percentile streamflow
conditions, 70th percentile average load and 95th percentile peak-
hour load (2009 IRP Technical Appendix, p. 120). On this basis,
during the five years 2011 through 2015, the IRP identifies the
months of April, May, June, July, August, September, November
and December as months which experience deficiencies. These
are the months that are assigned generation capacity costs in the
marginal cost analysis. The relative sizes of the five-year average
monthly deficiencies were used to define the share of annual
capacity cost assigned to each month.
(c) Idaho Power utilizes the results of its marginal cost analysis for cost-of-
service purposes in both its Idaho and Oregon jurisdictions. Since the adoption of the
3CP/12CP class cost-of-service study in Case No. IPC-E-08-10, the marginal cost of
generation capacity is no longer utilzed in cost studies prepared for Idaho rate filngs.
Because the 3CP/12CP class cost-of-service study allocates fixed costs associated with
base load and peaking resources separately, it is not necessary to weight the
associated allocation factors by the marginal cost of generation capacity. In the
Company's Oregon jurisdiction, the marginal cost of generation capacity is utilzed in the
marginal cost-based class allocation process according to the Public Utility Commission
of Oregon's preferred methodology.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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(d) The PDF file provided on the non-confidential CD contains the annual and
seasonal generation and transmission marginal costs for marginal cost analyses
completed since the 2002 IRP. The studies are related to the years 2003, 2005, 2007,
and 2008.
The annual and seasonal generation capacity marginal costs vary between test
years for a variety of reasons. For example, financial inputs can vary between test
years, including the general plant loaders, economic carrying charges, A&G loaders,
demand-related fixed operations and maintenance, as well as working capitaL. Other
non-financial inputs can also affect the seasonal nature of the generation capacity
marginal cost, such as the surplus/deficiencies that are identified in each IRP version.
While the input values may change with each analysis, the method for quantifying the
annual and seasonal generation capacity marginal costs has remained the same
between each yeats marginal cost analysis.
(e) The Company has not prepared a forecast of its marginal costs through
2015 and therefore has no analytical basis upon which to respond to this Request.
The response to this Request was prepared by Timothy E. Tatum, Senior
Manager of Cost of Service, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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REQUEST NO. 3-11: Mr. Tatum explains his responsibilties to include
overseeing the Company's cost-of-service activities, including marginal cost studies. (T.
Tatum, p. 3, 3-7.) Please respond to the following information requests related to
transmission capacity marginal costs.
(a) Please provide the inputs and calculations currently used by Idaho Power
to calculate transmission capacity marginal cost in native format (e.g., Excel) with all
links and formulas intact (if applicable). Please explain Idaho Powets rationale for
calculating transmission capacity marginal cost in this manner.
(b) Please provide the inputs and calculations currently used by Idaho Power
to seasonalize transmission capacity marginal cost in native format (e.g., Excel) with all
links and formulas intact (if applicable). Please explain Idaho Powets rationale for
seasonalizing transmission capacity marginal cost in this manner.
(c) Please explain how Idaho Power utilzes transmission capacity marginal
costs in the normal course of its business (e.g., rate design studies, demand side
management studies, contract negotiations), and please explain why Idaho Power
utilzes those marginal cost estimates in the manner that it does.
(d) To what extent have Idaho Power's transmission capacity marginal costs
varied on both an annual and seasonal basis over the period from and including Idaho
Powets 2002 Integrated Resource Plan through the present? What has been the
primary factor(s) that has caused Idaho Powets annual transmission capacity marginal
cost to vary over this time period? What has been the primary factor( s) that has caused
Idaho Powets seasonalized transmission capacity marginal costs to vary over this time
period?
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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(e) To what extent does Idaho Power believe its transmission capacity
marginal costs wil vary on both an annual and seasonal basis over the period from and
including Idaho Powets 2011 Integrated Resource Plan through 2015? What does
Idaho Power believe wil be the primary factor(s) that wil cause Idaho Power's annual
transmission capacity marginal cost to vary over this time period? What does Idaho
Power believe wil be the primary factor(s) that wil cause Idaho Powets seasonalized
transmission capacity marginal costs to vary over this time period?
RESPONSE TO REQUEST NO. 3-11:
(a) Please refer to the Excel file provided in the Company's response to the
DOE's Request No. 3-10(a).
The 2011 marginal cost analysis was prepared according to concept and design
specifications of the NERA marginal cost modeL. The NERA model is constantly being
refined but the basic concepts and methods have remained the same since Idaho
Power began using this method. The study identifies the long-run marginal cost of
providing electric service to new load on Idaho Powets system.
The marginal cost of transmission capacity includes the integration of new
resources as well as planned system expansion. The per unit marginal cost is
calculated by dividing the total forecasted investment for the integration of new
resources and planned system expansion by peak growth for the forecast period,
thereby creating a $/kW cost. This represents the Company's most accurate estimate
of the per unit cost of adding capacity to the Company's transmission system.
Additional detail regarding the derivation of the transmission capacity marginal
costs can be found on page 61 of Company witness Matthew T. Larkin's workpapers.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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(b) Please refer to the Excel file provided in the Company's response to the
DOE's Request No. 3-10(a).
The following description is included on page 61 of Mr. Larkin's workpapers:
Since the resource integration portion of marginal transmission
investment is driven by the need for new generation resources, as
identified in the 2009 IRP, these costs are assigned to months in
the same manner as marginal generation capacity costs. The
investment in the remainder of the network is driven by peak load
growth on the system, irrespective of the introduction of new
resources onto the grid. Therefore, that portion of marginal
transmission costs is assigned to the months based on relative
monthly peak load growth from 2011 through 2020. The two
portions are summed, by month. This method results in the
assignment of marginal transmission capacity costs to each of the
twelve months of the year.
(c) Idaho Power utilzes the results of its marginal cost analysis for cost-of-
service purposes in both its Idaho and Oregon jurisdictions. In the context of the
3CP/12CP class cost-of-service study prepared for Idaho rate filings, the marginal cost
of transmission capacity is utilzed to weight the "D13" allocation factor, which serves as
the allocation basis for costs associated with transmission investment. As stated on
page 7 of Exhibit No. 30:
The first step in deriving this factor is to calculate ratios based on
the sum of the actual coincident peak demands for each customer
class. Second, weighted coincident peak demand values are
derived by multiplying the actual monthly coincident peak demands
by the monthly transmission marginal costs. Corresponding
weighted ratios are then calculated for each customer class.
Finally, the actual ratios are averaged with the weighted ratios to
derive the non-seasonalized transmission allocation factor D13.
By using this approach, the Company is able to incorporate the seasonal nature
of transmission capacity costs into the class allocation process, while simultaneou~ly
mitigating any extreme impacts that the marginal costs may have on cost allocation. In
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
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the Company's Oregon jurisdiction, the marginal cost of transmission capacity is utilzed
in the marginal cost-based class allocation process according to the Public Utilty
Commission of Oregon's preferred methodology.
(d) Please refer to the Company's response to the DOE's Request No. 3-
10(d).
(e) Please refer to the Company's response to the DOE's Request No. 3-
10(e).
The response to this Request was prepared by Timothy E. Tatum, Senior
Manager of Cost of Service, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 22
REQUEST NO. 3-12: A discussion of marginal costs is included in Exhibit No.
30, page 5, in the paragraph that begins "(t)he marginal costs associated with new
resource integration."
(a) Please explain what Idaho Power means by "(t)he marginal costs
associated with new resource integration." Please provide the inputs and calculations
currently used by Idaho Power to calculate those marginal costs in native format (e.g.,
Excel) with all links and formulas intact (if applicable).
(b) Please explain what Idaho Power means by "(t)he marginal costs
associated with planned system expansions." Please provide the inputs and
calculations currently used by Idaho Power to calculate those marginal costs in native
format (e.g., Excel) with all links and formulas intact (if applicable).
RESPONSE TO REQUEST NO. 3-12:
(a) The marginal costs associated with new resources refer to the resources
that are identified in the preferred portolio of resources in Idaho Powets 2009 IRP.
Please refer to the Company's response to the DOE's Request No. 3-10 for the
marginal cost of energy.
(b) The marginal cost associated with planned system expansion refers to the
network investment that is driven by peak load on the Company's system, irrespective
of any new resources. Please refer to the Company's response to the DOE's Request
No. 3-10 for the marginal cost of energy.
The response to this Request was prepared by Timothy E. Tatum, Senior
Manager of Cost of Service, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 23
REQUEST NO. 3-13: Per Mr. Larkin, page 31, 1-2, Idaho Powets "(u)pdated
marginal energy costs were calculated for the five-year period 2011 through 2015."
Also, Idaho Power explains in Exhibit No. 30, page 5, that "(u)pdated marginal energy
costs are calculated by quantifying the difference in net power supply costs resulting
from the addition of 50 megawatts of load to all hours of the Company's base case
system simulation run for the five-year planning period." Please respond to the
following information requests related to Idaho Power's marginal energy costs.
(a) Please explain Idaho Power's rationale for calculating marginal energy
costs in this manner.
(b) Please provide total net power supply costs from the base case system
simulation run by month for the planning period 2011 through 2015 in Excel format.
(c) Please provide net power supply costs from the base case system
simulation run by month for the planning period 2011 through 2015 in Excel format
disaggregated by source of supply for the following cost categories: costs associated
with coal-fired plants; costs associated with hydropower plants; costs associated with
purchased power; costs associated with natural gas-fired combined cycle plants; costs
associated with natural gas-fired combustion turbines; revenues associated with surplus
sales; and all other costs.
(d) Please provide Idaho Powets natural gas price inputs from the base case
system simulation run by month for the planning period 2011 through 2015 in Excel
format.
(e) Please provide Idaho Powets wholesale market electricity price inputs
from the base case system simulation run by month for the planning period 2011
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 24
through 2015 in Excel format. If Idaho Power used different price inputs to model
purchases and sales, please provide both sets of price inputs.
(f) Please provide total net power supply costs by month for the planning
period 2011 through 2015 in Excel format from the simulation run that includes
incremental loads of 50 megawatts above the base case simulation in all hours.
(g) Please provide net power supply costs from the simulation run that
includes incremental loads of 50 megawatts above the base case simulation in all hours
by month for the planning period 2011 through 2015 in Excel format disaggregated by
source of supply for the following cost categories: costs associated with coal-fired
plants; costs associated with hydropower plants; costs associated with purchased
power; costs associated with natural gas-fired combined cycle plants; costs associated
with natural gas-fired combustion turbines; revenues associated with surplus sales; and
all other costs.
(h) Please provide Idaho Powets incremental marginal energy costs by
month and by hour for the planning period 2011 through 2015 in Excel format. Please
also provide the derivation of the requested marginal energy costs.
(i) Please provide total net power supply costs by month for the planning
period 2011 through 2015 in Excel format from a simulation run that includes
decremental loads of 50 megawatts below the base case system simulation in all hours.
U) Please provide net power supply costs from a simulation run that includes
decremental loads of 50 megawatts below the base case system simulation in all hours
by month for the planning period 2011 through 2015 in Excel format disaggregated by
source of supply for the following cost categories: costs associated with coal-fired
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 25
plants; costs associated with hydropower plants; costs associated with purchased
power; costs associated with natural gas-fired combined cycle plants; costs associated
with natural gas-fired combustion turbines; revenues associated with surplus sales; and
all other costs.
(k) Please provide Idaho Powets decremental marginal energy costs by
month and by hour for the planning period 2011 through 2015 in Excel format based
upon the previously requested decremental net power supply cost simulation and Idaho
Powets base case system simulation. Please also provide the derivation of the
requested marginal energy costs.
(I) To what extent have Idaho Powets marginal energy costs varied on both
an annual and seasonal basis over the period from and including Idaho Powets 2002
Integrated Resource Plan through the present? What has been the primary factor(s)
that has caused Idaho Powets annual and monthly marginal energy costs to vary over
this time period?
(m) What does Idaho Power believe wil be the primary factor(s) that wil cause
Idaho Powets annual and monthly marginal energy costs to vary over the planning
period 2011 through 2015?
RESPONSE TO REQUEST NO. 3-13:
(a) The methodology used for calculating the marginal energy costs used in
the marginal cost analysis is a methodology that has been accepted by the Idaho Public
Utilities Commission in past general rate case proceedings. The methodology is
designed to identify the additional cost for the next unit of energy.
(b) Please see the Excel file provided on the non-confidential CD.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 26
(c) Please see the Excel file provided on the non-confidential CD.
(d) The response to this Request contains confidential information and wil be
provided separately to those parties that have executed the Protective Agreement in
this docket.
(e) The AURORA model is used to calculate the marginal energy costs that
are used in the marginal cost analysis. The AURORA model is a comprehensive
electric market forecasting model that applies economic principles and dispatch
simulation to model the relationships between generation, transmission, and demand to
forecast electric market prices. Since AURORA forecasts electric market prices, it is not
necessary to input electric market prices.
(f) Please see the Excel file provided on the non-confidential CD.
(g) Please see the Excel file provided on the non-confidential CD.
(h) Please see the Excel file provided on the non-confidential CD. The
AURORA model is an hourly model; however, the hourly information is aggregated into
monthly and annual numbers.
(i) As explained on page 59 of Matthew T. Larkin's workpapers, the marginal
cost analysis uses a base case run and a base case plus 50 megawatt ("MW") run. A
base case minus 50 MW run is not performed.
G) Please refer to the Company's response to the DOE's Request No. 3-
13(i).
(k) Please refer to the Company's response to the DOE's Request No. 3-
13(i).
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 27
(I) Please refer to the Company's response to the DOE's Request No. 3-
10(d).
(m) Please refer to the Company's response to the DOE's Request No. 3-
10(e).
The response to this Request was prepared by Timothy E. Tatum, Senior
Manager of Cost of Service, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 28
REQUEST NO. 3-14: In Idaho Powets 2011 Integrated Resource Plan, page
57, Idaho Power states, "(h)istorically, Idaho Power has been a summer peaking utilty
with peak loads driven by irrigation pumps and air conditioning in the months of June,
July, and August."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
RESPONSE TO REQUEST NO. 3-14:
(a) Please see the Excel file provided on the non-confidential CD which
provides the Company's annual and summer peaks for the time period 1970 through
2010. As shown in this Excel file, Idaho Power has been a summer peaking utilty since
1994, and has only experienced two winter peaking years since 1970.
Additionally, please refer to the attachments provided in the Company's response
to the DOE's Request No. 3-9(b), which contain hourly load shapes by class developed
from 2010 load research data. As shown by these shapes, irrigation loads are highest
during the summer peaking months of June, July, and August. These shapes also
show an increase in residential summer loads relative to fall and spring loads, especially
during mid-afternoon and evening hours.
(b) Please see the Company's response to the DOE's Request No. 3-14(a).
The response to this Request was prepared at the direction of M. Mark Stokes,
Manager, Power Supply Planning, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 29
REQUEST NO. 3-15: In Idaho Powets 2011 Integrated Resource Plan, page
60, Idaho Power states, "(s)ummertime peak-hour load growth accelerated in the
previous decade as air conditioning became standard in nearly all new residential home
construction and new commercial buildings."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
RESPONSE TO REQUEST NO. 3-15: Please see the table provided in the
Company's response to the DOE's Request No. 3-16(b). In the "Penetration" section of
this table, the column titled "CAC" represents historical and forecasted central air
conditioning saturation for the time period 1988 through 2030. As shown by these
numbers, the percentage of homes with central air conditioning has consistently
increased annually since 1988. This information aligns with the hourly class load
shapes contained in the attachments provided by the Company in its response to the
DOE's Request No. 3-9, and referenced in the Company's response to the DOE's
Request No. 3-14. As stated in the Company's response to the DOE's Request No. 3-
14, "These shapes . . . show an increase in residential summer loads relative to fall and
spring loads, especially during mid-afternoon and evening hours."
The response to this Request was prepared at the direction of M. Mark Stokes,
Manager, Power Supply Planning, Idaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 30
REQUEST NO. 3-16: In Idaho Powets 2011 Integrated Resource Plan, page
60, Idaho Power states, "(i)n another improvement to this year's forecast, Idaho Power
used Itron, Inc.'s residential Statistically Adjusted End-Use (SAE) model to prepare the
long-term residential sales forecast. Recently, many utilities have adopted Itron, Inc.'s
SAE modeling approach to include greater end-use information into the forecasting
process."
(a) Please list the end-use information Idaho Power utilzed to develop its
residential sales forecast.
(b) Please provide the historical and projected end-use information on
residential air conditioning utilzed by Idaho Power in its forecast model development.
RESPONSE TO REQUEST NO. 3-16:
(a) The following list of end-use applications was incorporated into the
residential forecast.
. Electric furnace and resistant room space heaters
. Heat pump space heating
. Central air conditioning
. Heat pump space cooling
. Room air conditioners
. Electric water heating
. Electric cooking
. Refrigerator
. Second refrigerator
. Freezer
. Dishwasher
. Electric clothes washer
. Electric clothes dryer
. TV sets
. Lighting
. Miscellaneous electric appliances
. Dwellng thermal integrity
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 31
Saturation and efficiency history and forecasts from the National Energy
Modeling System/ Annual Energy Outlook database served as the basis for integrating
into the Idaho Power forecast modeL.
(b) The below table contains air conditioning data used in the forecast modeL.
Column headers are as follows:
CAC = Central Air Conditioning
HPCool = Heat Pump Cooling
RAC = Room Air Conditioning
Penetration
CAC HPCool
34.8%
35.4%,
'36:6%' .
36.7%
37.3õJ~
37.9%"
38.5%:
39.1%
39.8%
40.4%,
41~6%'
41.6%"
....42.3%
42.9%'
43.5%'
44.1'%:
44.8%'
45.4%
45.9%
46.6%'
47.2%
47'9%'
48.6%
. 49.
49.
50.4olo'
51.6%
51.6%'
52.2%
5:2.8%
53.4%
53.9%
54:5%
55.6%
55.5%
56.0%
56.5%
56.9%
57.4%
57.8%
58.30/0
58.7%
59.1%
Year
.. 1988
...).98~~..1990l
1991'
.1992,
;i9~31
1994~
1995'
19960' t
1997~
.1998,
19~9.
~OOO;
2001
. 200"2~ .
2003
2004
2005..
2008
2009.
2010.
2011'
2012.
2013,
20141
2015:
2016;
2017
2018;
2019
2020
2021
2022
2023
2024
2025
2026
2Q27:
2028
2029""T2030
"4.4%
. 4:5%1'
4.6%1
'-4:8"%;......-+.4.9%1
5:1%"'"
5.2%1
"5:-3%
5.5%,
5:6%'
lf8õJ: ...
'5.9%'
6.1%'
6.
Ë~.
6.5%
6.6'%'
6.8%'
6.9%
7:0%'
7.2%"
f'3%'
7.4%
'7.5%
7:6%
7.7%'
7.80/;'
'7.8%"
7.9%'
....7.9%
8.0%
8.6%
8.1%
8.1%
'8:2%
8.2%
8.2%
8.3%
8.3%
8.3%
8.3%
8.40/0
RAC
8.2%
8.
8.6%:
8.8%
'9.1%:
9."3%-
9.5%1
9.8%
10J)"%.
10.2%'
'Ül:5%
10.7%
10.9%
11.2%
11.4%'
11.6%
11.9%
....12.fo/~.
12.4%
12.6%
12.9%
13.2%
13.5%
13.8%"
'14.1%
14.3%
14:6%
14.9%
15.2%
15.4%
15.7% .
16.0%
16.2%
16.5%
16.7%
16.9%
17.1%
17.3%
17.6%
17.8%
18.0%
18.1%
18.3%
Efficienc: Indicies
CAC HPCool
7.58 8.00
7.80 8.24. . ..... ..-.. .'. ..' . .. .j8.02 ' 8.49 i
...... ¡. ........ .1.8.24' 8.74 I1992 8:46 T 8:00 "1
.. . .i.~~.31. .. ~. .. ~:~~~.. .... . ~:~~ ì . .1994; 8.91 ; 9.49 !1995: 9.13' 9."74 '"'-'~N".'f ".~,.,- , . .,'-'''',.,'''+1996 9.35 .. 9.99 ¡~'" -.' ,- "+ ~-",'.' .-199 9.57 í 10.21!Ú9 . .. "'1CI.49 i
1999,10.62 :"" 10:74ì," ""'""''¡" ,,"'~,.,~_,_,_+ w~".~,~",'," 'j"2000 10.24 10.99 iw _ ,m,,"? .' 0.- ,~ _.","",-' i-'"2001 10.46 11.24 í
2002" "16.68 ,1'1:49 ¡.. .200310:90 " H.74 j2004 ft:13 .11.99' .2005"'11:35' 12:24-;
2006: . 11.60, 12~47 · .
. 2007~ 11.85. 12:71
2008' 12.09 ; 12.92 12009 1"2.31 . 13.08 i20101:2:48 '13.18 f'201i': 12.ri ,13.31 ¡~'- ~ _. v".,_,_,, " t "'-, "._-- -- , -f'N'"2012 12.84 .. 13.44 '
2013 . .. 13."06 ;'13.56 ;. ., ... , .' ..... ....... "' ......,.'12014 13.15 : 13.67 ,
2015' . 13.29: . 13077 r. ,. ... .... ......... . .....!.
2016, . .!~.~1 13.8E) .2017 13.50 . 13.90 :2018 13.59 ,. 13.96"2019' 13.67 . 14.00 ¡
2020' 13.79' 14:0612021 13.87 ' 14.10 '
2022" 13.94 14.13 ¡
2013' 14.00 14.15
2024 14.06 14.17
2025' 14.12 14.19
2026 14.1'7 14.20
2027 14.23 14.21
2028 14.28 14.22
2029 '14.33 14.232030' 14.38 14.26'
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 32
9.37
9:49
"9.55
9:66
9:65
9.701
"9.75 ¡.~'.' .,",.,._, .,l9.80 i
~.~~¡9.87 :"'9.90:
9:921
9.94"~
9.95 ;.. .. .... t9.96 .-''''''-''.'''''l,9.97 :
9.99'
10.01
10".02.
10.03.
. 10.04"
. 10.05 .
10.06 .
10.06
10.07
10.08
10.09
The response to this Request was prepared by Bradford Snow, Senior Planning
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 33
REQUEST NO. 3-17: Please list, describe, and provide in Excel format the
hourly load shapes used by Idaho Power in the preparation of its 2011 Integrated
Resource Plan. Please also provide the derivation of the requested hourly load shapes.
RESPONSE TO REQUEST NO. 3-17: The load forecast used in the 2011 IRP is
a monthly average load and a monthly peak load as described in Appendix A to the
2011 IRP. The hourly load forecasts for long-term planning are developed by extending
the hourly load forecast that Idaho Power uses for short- and medium-term planning. In
summary, typical meteorological month weather forecasts are developed based on
historical months where the monthly heating-degree-day or cooling-degree-day values
closely conform to the monthly values used in the median and 70th percentile forecasts.
The typical meteorological months are combined with the calendar data to generate a
preliminary hourly load forecast using Idaho Powets hourly load forecast modeL. The
preliminary hourly load forecast is then mathematically adjusted to have same average
load and peak load for every month of the planning period as the long-term forecast
reported in Appendix A to the IRP. The hourly values used in Idaho Powets 2011 IRP
provided on the confidential CD. The confidential CD wil be provided to those parties
that have executed the Protective Agreement in this docket.
The response to this Request was prepared by Thomas A. Noll Ph.D., Senior
Planning Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 34
REQUEST NO. 3-18: Mr. Sparks describes the Company's proposed
methodology that was used to calculate the proposed rate component adjustments for
Schedules 7,9, and 19. (S. Sparks, p. 4, 1-19.)
(a) Please provide workpapers in native format (e.g., Excel) with all links and
formulas intact (if applicable) that show specifically how this methodology was applied in
developing the proposed Schedule 19 secondary voltage rate components shown on
Exhibit No. 47, page 6.
(b) Please provide workpapers in native format (e.g., Excel) with all links and
formulas intact (if applicable) that show specifically how this methodology was applied in
developing the proposed Schedule 19 primary voltage rate components shown on
Exhibit No. 47, page 7.
(c) Please provide workpapers in native format (e.g., Excel) with all links and
formulas intact (if applicable) that show specifically how this methodology was applied in
developing the proposed Schedule 19 transmission voltage rate components shown on
Exhibit No. 47, page 8.
RESPONSE TO REQUEST NO. 3-18: Please see the Excel files provided by
the Company in its response to the IIPA's Data Request No. 26 for workpapers in Excel
format. Specifically, see Excel file Sparks Workpapers - Rate Oesign.xlsx tab "119S" for
Schedule 19 secondary voltage rate components, tab "119P (2)" for Schedule 19
primary voltage rate components, and tab "119T (2)" for Schedule 19 transmission
voltage rate components.
The response to this Request was prepared by Scott D. Sparks, Senior
Regulatory Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 35
REQUEST NO. 3-19: Idaho Powets proposed rate design for Schedule 24
includes a proposal that "the Company is proposing to move the individual rate
components 5 percent closer to the costs indicated by" the Company's class cost-of-
service study. (S. Sparks, p. 15,8-12.)
(a) Please provide workpapers in native format (e.g., Excel) with all links and
formulas intact (if applicable) that show specifically how this methodology was applied in
developing the proposed Schedule 24 secondary voltage rate components shown on
Exhibit No. 47, page 9.
RESPONSE TO REQUEST NO. 3-19: Please see the Excel files provided by
the Company in its response to the IIPA's Data Request No. 26 for workpapers in Excel
format. For Schedule 24 secondary voltage rate components, see tab "124S (6%)" in
Excel file Sparks Workpapers - Rate Oesign.xlsx.
The response to this Request was prepared by Scott D. Sparks, Senior
Regulatory Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 36
REQUEST NO. 3-20: Idaho Powets Exhibit No. 45 includes Idaho Powets
proposed projected 2011 test-year billng determinants for multiple residential rate
classes. (D. Nemnich, Exhibit No. 45.) Please provide the historical actual monthly
billing determinants for the period 2006 through the present for rate class Schedules 1,
3, 4, and 5 in Excel format. Please explain changes in the definitions of billng
determinants over this time period, if any. To the extent available, please provide the
weather normalized billng determinants for these rate schedules over the same time
period.
RESPONSE TO REQUEST NO. 3-20: Historical monthly biling determinants on
an actual basis are provided for all Idaho rate schedules in electronic format for 2008
through 2010 in the confidential Excel file, ActualBillngCompns 2008-2010, provided on
the confidential CD. The confidential CD wil be provided to those parties that have
executed the Protective Agreement in this docket. For the Company's standard rate
schedules, data for 2006 and 2007 is only available in hard copy format and has been
provided as PDF files on the non-confidential CD. Actual usage data for rates 26, 29,
30, and 32 is confidential and is only being provided to parties that have executed the
Protective Agreement in this docket. This confidential usage data for 2006 and 2007 is
provided in the Excel file, ActuaISpecIContrctBillngCompons2006-2007, provided on
the confidential CD. Please note that these values are estimated for the sole purpose of
determining test year billng determinants and have been adjusted and annualized to
reflect rate structures in effect as of December 31 of each historical year. It should also
be noted that although the PDF files for the years 2006 and 2007 contain columns
labeled "Revenue" and "Actual Revenue," these numbers do not reflect actual biled
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 37
revenues. Because "base rate" revenue is not tracked on an actual basis, it was the
Company's practice to calculate actual revenues by applying current rates to estimated
actual biling determinants. These calculated revenues do not tie to actual booked
revenues, and were only used for internal informational purposes. The Company
discontinued this practice after the 2007 reporting year.
Weather normalized billng determinants were provided in the files provided by
the Company in its response to the IIPA's Data Request NO.3. In the same response,
the Company provided a table detailng rate structures in effect in its Idaho jurisdiction
from June 1, 2005, through May 31, 2011. This table reflects any changes to biling
determinant definitions over that time period for each rate class.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 38
REQUEST NO. 3-21: Idaho Powets Exhibit No. 47 includes Idaho Powets
proposed projected 2011 test-year biling determinants for multiple non-residential rate
classes. (S. Sparks, Exhibit No. 47.) Please provide the historical actual monthly biling
determinants for the period 2006 through the present for rate class Schedules 7, 9, 19,
and 24 by voltage level, if applicable, in Excel format. Please explain changes in the
definitions of billng determinants over this time period, if any. To the extent available,
please provide the weather normalized billng determinants for these rate schedules
over the same time period.
RESPONSE TO REQUEST NO. 3-21: Please see the Company's response to
the DOE's Request No. 3-20.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 39
REQUEST NO. 3-22: Idaho Powets Exhibit No. 43 includes Idaho Powets
proposed projected 2011 test-year billng determinants for multiple non-residential rate
classes. (M. Youngblood, Exhibit No. 43.) Please provide the historical actual monthly
billng determinants for the period 2006 through the present for rate class Schedules 26,
29, 30, and 32 in Excel format. Please explain changes in the definitions of billng
determinants over this time period, if any. To the extent available, please provide the
weather normalized billng determinants for these rate schedules over the same time
period.
RESPONSE TO REQUEST NO. 3-22: Please see the Company's response to
the DOE's Request No. 3-20.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 40
REQUEST NO. 3-23: Idaho Power "used 2010 load research data to derive the
coincident demand values used in the cost-of-service study prepared in this proceeding"
rather than "the five-year median approach." (M. Larkin, p. 19, 11-20.) Please provide
the data that would be necessary to calculate the five-year median approach in Excel
format.
RESPONSE TO REQUEST NO. 3-23: The requested data would require a
labor-intensive adjustment to historical data that the Company has not performed. As
described on page 23 of the Direct Testimony of Company witness Matthew T. Larkin,
coincident demand values used in the cost-of-service study in this proceeding were
derived according to "historical load data (that) was adjusted to reflect system loads that
would have occurred had no (demand response) programs been in effect." Because the
coincident peak demand values in this case were derived from 2010 historical load
research data, the described adjustment has not been made to historical data for years
prior to 2010. To create a consistent historical dataset necessary to calculate
coincident demand values according to the five-year median approach would require
the Company to adjust historical load research data for each year 2006 through 2009 in
the manner described.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst, tdaho Power Company, in consultation with Lisa D. Nordstrom, Lead Counsel,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 41
REQUEST NO. 3-24: In Idaho Powets 2011 Integrated Resource Plan, page
79, Idaho Power states, "(h)istorically, Idaho Power has been a summer peaking utility,
while most other utilties in the Pacific Northwest experience system peak loads during
the winter."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
RESPONSE TO REQUEST NO. 3-24: The Northwest Power and Conservation
Council ("NWPCC") writes in the Sixth Power Plan, "The Northwest has always been a
winter-peaking power system." NWPCC, Sixth Power Plan, Council Document 2010-
09, page 3-1, February 2010. Additional information regarding regional electricity
demand is described in Chapter 3 of the NWPCC's Sixth Power Plan, Electricity
Demand Forecast. Information concerning the peak electricity demand of Idaho Power
customers was provided in the Company's response to DOE's Request No. 3-14.
The response to this Request was prepared by Thomas A. Noll Ph.D., Senior
Planning Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY -42
REQUEST NO. 3-25: In Idaho Powets 2011 Integrated Resource Plan, page
79, Idaho Power states, "Idaho Power purchases energy from the Mid-Columbia energy
trading market to meet peak summer load and sells excess energy to Pacific Northwest
utilities during winter and spring."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
(c) What is the magnitude of purchases in megawatt-hours that Idaho Power
made to "meet peak summer load" during each summer month over the time period
beginning in 2006 and continuing through the present? Please also provide the
derivation of the requested information on purchases.
(d) Are the purchases made by Idaho Power to meet peak summer loads
independent of the excess sales Idaho Power makes to Pacific Northwest utilties during
winter and spring? Please explain.
RESPONSE TO REQUEST NO. 3-25:
(a-b) Idaho Power has followed the seasonal pattern of winter and spring sales
and summer purchases for many years. One early reference showing the winter and
spring sales and the summer purchases is contained in Idaho Powets 1993 IRP,
Technical Appendix, pages 49 and 50, showing the monthly sales and purchases for
1988 through 1992 (pages 49 and 50 are provided on the non-confidential CD). The
pattern persists and is expected to continue into the future. Idaho Powets 2011 IRP
discusses the Company's load and resource balance beginning on page 85. Figures
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 43
8.1 and 8.2 of Idaho Power's 2011 IRP show the same seasonal pattern of energy
surpluses in the winter and spring with smaller energy surpluses, and even energy
deficits beginning in 2017, during the summer months.
(c) The table below shows the magnitude of the net-fixed price term
transactions in average megawatts ("aMW") Idaho Power executed for summer heavy
load hours prior to entering the delivery months.
Net Purchases (aMW)
Year June July August
2006 -367 308 408
2007 658 733 558
2008 158 433 283
2009 108 508 158
2010 233 507 439
2011 233 308 359
(d) The sales and purchases are generally independent. However, Idaho
Power does occasionally enter into energy exchange agreements.
The response to this Request was prepared by Thomas A. Noll Ph.D., Senior
Planning Analyst, Idaho Power Company, and John Anderson, Manager of Power
Supply Operations, Idaho Power Company, in consultation with Lisa D. Nordstrom,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 44
REQUEST NO. 3-26: In Idaho Powets 2011 Integrated Resource Plan, page
79, while referring to its practice of making purchases from the Mid-Columbia energy
trading market to meet peak summer load and sellng excess energy to Pacific
Northwest utilities during winter and spring, Idaho Power states, "(t)his practice benefits
the environment and Idaho Powets customers because the construction of additional
peaking resources to serve summer peak load is delayed or avoided, revenue from off-
system sales during the winter and spring is credited to customers through the PCA,
and revenue from others' use of the transmission system is credited to customers in
general rates."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
(c) Please quantify the magnitude of peaking resources that have been
"delayed or avoided" as a result of this practice. Please also provide the derivation of
the requested information on peaking resources.
RESPONSE TO REQUEST NO. 3-26:
(a) As discussed in the Company's responses to DOE's Request Nos. 3-14,
3-24, and 3-25, Idaho Power is a summer peaking utility and the Northwest is winter
peaking. Mutual trade is beneficial to both parties as shown in numerous economic text
books including Microeconomic Theory, A Mathematical Approach, Third Edition,
Henderson, J. M., and R. E. Quandt, McGraw-Hil, 1980, pages 237-240.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 45
(b) Please see the Company's responses to DOE's Request Nos. 3-14, 3-24,
and 3-25.
(c) Idaho Power's 2011 IRP, Technical Appendix, "Peak-Hour Load and
Resource Balance," pages 44 through 63, indicate the magnitude of peaking resources
that Idaho Power has delayed or avoided through mutual trade with the Northwest
power market. For example, the data for July 2012 on page 45 indicates that Firm
Pacific NW Import Capacity is 233 MW. The firm import capacity means that Idaho
Power has delayed or avoided 233 MW of peak hour generation resources in ~uly 2012.
The response to this Request was prepared by Thomas A. Noll Ph.D., Senior
Planning Analyst, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 46
REQUEST NO. 3-27: In Idaho Powets 2011 Integrated Resource Plan, pages
81-82, Idaho Power states, "(t)he Idaho-Northwest path is most likely capacity-limited
during summer months in low-to-normal water years due to transmission-wheeling
obligations for BPA's eastern Oregon and south Idaho loads and energy imports from
the Pacific Northwest to serve Idaho Powets retail load."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
(c) For the period 2006 through the present, please explain when this
transmission path was capacity-constrained with respect to Idaho Power's abilty to use
this path to import power to serve its retail load.
(d) For the period 2006 through the present, please explain when this
transmission path was not capacity-constrained with respect to Idaho Powets abilty to
use this path to import power to serve its retail load.
RESPONSE TO REQUEST NO. 3-27:
(a) The Idaho-Northwest path has a Total Transfer Capability of 1200 MW
that is evaluated seasonally. During the summer periods, Idaho Power historically could
simultaneously import up to 1090 MW according to Western Energy Coordinating
Council ("WECC") operating transfer studies. For the peak summer month of July,
Idaho Power sets aside about 304 MW of transfer capabilty (Transmission Reserve
Margin) to manage adverse average clockwise loopflow in the WECC system. In
addition, Idaho Power sets aside 330 MW of transfer capabilty (Capacity Benefit
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 47
Margin) to cover unplanned unit outages. Idaho Power also imports its share of the
Boardman Project across this interface as well as other entity imports to service their
loads in southern Idaho and eastern Oregon. This leaves approximately 100 MW of
transfer capability to service Idaho Power loads.
(b) These capacity constrained conditions have existed for at least 10 years.
(c) The Idaho-Northwest path is capacity constrained May, June, July,
August, September, and December.
(d) The Idaho-Northwest path is not constrained in January, February, March,
April, October, and November. In these months, other transmission customers have
access to any surplus capacity not used by Idaho Power to service its native load.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 48
REQUEST NO. 3-28: In Idaho Powets 2011 Integrated Resource Plan, page
82, Idaho Power states, "(t)he Brownlee East path is most likely to face capacity
limitations in the summer during normal-to-high water years. The capacity limitations
result from a combination of Hells Canyon Complex hydroelectric generation flowing
east to the Treasure Valley, concurrent with transmission-wheeling obligations for BPA's
eastern Oregon and southern Idaho loads and Idaho Power energy imports from the
Pacific Northwest."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
(c) For the period 2006 through the present, please explain when this
transmission path was capacity-constrained with respect to Idaho Power's abilty to use
this path to import power to serve its retail load.
(d) For the period 2006 through the present, please explain when this
transmission path was not capacity-constrained with respect to Idaho Powets abilty to
use this path to import power to serve its retail load.
RESPONSE TO REQUEST NO. 3-28:
(a) The Brownlee East 230 kilovolt ("kV") path when combined with the
Summer Lake-Hemingway 500 kV line has a Total Transfer Capabilty of 2315 MW that
is evaluated seasonally. As explained, in normal to high water years, the hydro
production in the Roach Complex (Brownlee, Oxbow, and Hells Canyon) can reach in
excess of 1300 MW. Adding to that production to account for Transmission Reserve
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 49
Margin (304 MW) and Capacity Benefit Margin (330 MW) (see the Company's response
to DOE's Request No. 3-27), integration of the Elkhorn Wind Project (66 MW), importing
Idaho Power's share of the Boardman Project (53 MW), and other entity network load
service, no surplus capacity remains to import power under these conditions.
(b) These capacity limitations have existed for at least 10 years.
(c) The Brownlee East path is capacity constrained January, May, June, July,
August, September, and December.
(d) The Brownlee East path is not constrained in February, March, April,
October, and November. In these months, other transmission customers have access
to any surplus capacity not used by Idaho Power to service its native load.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 50
REQUEST NO. 3-29: In Idaho Powets 2011 Integrated Resource Plan, page
82, Idaho Power states, "(t)he Idaho-Montana path is also capacity-limited during the
summer months as Idaho Power and others move energy south from Montana into
Idaho."
(a) Please provide the information relied upon by Idaho Power in making this
statement.
(b) Over what historical time period does Idaho Power believe this statement
is true?
(c) For the period 2006 through the present, please explain when this
transmission path was capacity-constrained with respect to Idaho Powets abilty to use
this path to import power to serve its retail load.
(d) For the period 2006 through the present, please explain when this
transmission path was not capacity-constrained with respect to Idaho Powets ability to
use this path to import power to serve its retail load.
RESPONSE TO REQUEST NO. 3-29:
(a) The Idaho-Montana path is the combination of the Hot Springs-Milcreek-
Antelope-Brady 230 kV line and the Dilon-Jefferson-Goshen 161 kV line. Idaho
Power's in-bound capacity rights are 167 MW that is evaluated seasonally. Idaho
Power imports a small share of the Boardman Project (7 MW) over these lines, as well
as purchases of Public Utility Regulatory Policies Act of 1978 contracts and a capacity
purchase from PPL Montana (80MW) during the summer months. A portion of other
entity network load service is also scheduled via this path (52 MW), which leaves about
21 MW for Idaho Powets native load service during critical water years.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 51
(b) These capacity limited conditions have existed for at least 10 years.
(c) The Idaho-Montana path is capacity constrained May, June, July, August,
September, and December.
(d) The Idaho-Montana path is not constrained in January, February, March,
April, October, and November. In these months, other transmission customers have
access to any surplus capacity not used by Idaho Power to service its native load.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 52
REQUEST NO. 3-30: In Idaho Powets 2011 Integrated Resource Plan, page
83, while referring to the Idaho-Utah path, which is referred to as Path C, Idaho Power
states, "(t)he path effectively feeds into Borah West path when power is moving from
east-to-west and, consequently, the import capability of Path C is limited by Borah West
path capacity limitations." In Idaho Powets 2011 Integrated Resource Plan, page 82,
while referring to the Borah West path, Idaho Power states, "(t)he Borah West path is
capacity constrained during summer months due to transmission wheeling obligations
coinciding with high eastern thermal and wind production."
(a) Please provide the information relied upon by Idaho Power in making
these statements.
(b) Over what historical time period does Idaho Power believe these
statements are true?
(c) For the period 2006 through the present, please explain when Path C or
Borah West were capacity-constrained with respect to Idaho Powets ability to use
these paths to import power to serve its retail load.
(d) For the period 2006 through the present, please explain when Path C or
Borah West were not capacity-constrained with respect to Idaho Power's abilty to use
these paths to import power to serve its retail load.
RESPONSE TO REQUEST NO. 3-30:
(a) The Borah West path consists of three 345 kV lines, one 230 kV line, and
one 138 kV line. The total transfer capabilty of the path is currently 2,557 MW that is
evaluated seasonally. This path is most constrained during light load hours when loads
are light and coal production is used to permit "reservoir refil." Idaho Power has other
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 53
transfer commitments which reduce the available capacity to about 954 MW. Idaho
Power resources east of Borah West include the Jim Bridger Project (currently 710 MW
with more capacity upgrade projects expected), the American Falls Project (110MW),
several wind projects, and imports from Montana-Idaho interconnections discussed in
the Company's response to the DOE's Request No. 3-29. After accounting for light
loads east of the Borah West path, little capacity (15 MW) is available on a short-term
basis. Idaho Power expects the path to be fully subscribed in 2012.
(b) These capacity limitations have existed for at least 10 years.
(c) The Borah West path is capacity most limiting during May, June, July,
August, and September.
(d) The Borah West path is not constrained in January, February, March,
April, October, November, and December. In these months, other transmission
customers have access to any surplus capacity not used by Idaho Power to service its
native load.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 54
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 56
REQUEST NO. 3-32: Please provide the peak load and annual energy during
2010 for loads within the Treasure Valley load center.
RESPONSE TO REQUEST NO. 3-32: Idaho Power peak load for 2010 for the
loads within the Treasure Valley was 1,814 MW. The annual energy was 8,952,745
megawatt-hours ("MWh").
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 57
REQUEST NO. 3-33: Please provide the peak load and annual energy during
2010 for loads located east of Midpoint West path and west of Borah West path.
RESPONSE TO REQUEST NO. 3-33: Idaho Power peak load for 2010 for the
loads east of Midpoint West and west of Borah West path was 850 MW. The annual
energy was 3,806,889 MWh.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
JNTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 58
REQUEST NO. 3-34: Please provide the peak load and annual energy during
2010 for loads located east of Borah West path.
RESPONSE TO REQUEST NO. 3-34: Idaho Power peak load for 2010 for the
loads east of Borah West path was 430 MW. The annual energy was 1,967,131 MWh.
The response to this Request was prepared by Ronald D. Schellberg, Consulting
Engineer, Idaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 59
REQUEST NO. 3-35: In Idaho Powets 2011 Integrated Resource Plan, page
122, Idaho Power states, "(t)he preferred portolio also includes a market purchase from
the east side of Idaho Powets system. The purchase is necessary to cover a summer
peak-hour deficit in 2015 that exists before the Boardman to Hemingway line becomes
available in 2016. Idaho Power has used the east side for market purchases in the
past, but prices have historically been higher than the prices at the Mid-C hub in the
Pacific Northwest. A purchase on the east side does not require substantial lead time,
and Idaho Power wil continue to monitor market prices, load growth, and the status of
the Boardman to Hemingway project prior to committing to this purchase."
(a) Is the peak-hour deficit to which Idaho Power refers the 83 megawatt
deficit shown under the row heading "2015 Eastside Purchase" in July 2015 listed in
Idaho Power's 2011 Integrated Resource Plan, Appendix C, page 48?
(b) Please explain the energy figures shown under the row heading "2015
Eastside Purchase" on Idaho Powets 2011 Integrated Resource Plan, Appendix C,
page 26.
(c) Please provide specific examples of east side purchases that Idaho Power
has made in the past, and list the actual eastside purchases that were made during the
period including 2006 through the present."
(d) Please provide the information relied upon by Idaho Power in making the
statement that "prices have historically been higher than the prices at the Mid-C hub in
the Pacific Northwest."
(e) Please explain exactly what Idaho Power meant when it said ural purchase
on the east side does not require substantial lead time."
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 60
(f) Over which transmission path (e.g., Idaho-Utah path) does Idaho Power
anticipate making this purchase?
RESPONSE TO REQUEST NO. 3-35:
(a) Yes.
(b) The values shown on page 26 of Appendix C to Idaho Powets 2011 IRP
are the average energy calculations. For example, using the Eastside Purchase values
on pages 26 and 48, the average energy value is 45 aMW and the peak-hour value is
83 MW. The average energy value of 45 MW indicates that the 83 MW wil be needed
for approximately one-half of the hours in July 2015.
(c) The response to this Request contains confidential information and wil be
provided separately to those parties that have executed the Protective Agreement in
this docket.
(d) The Intercontinental Exchange ("ICE") daily Heavy Load ("HL") index price
average for the month for Mid-C, Four Corners, and Palo Verde Trading Hubs are
shown below. Four Corners and Palo Verde trading hubs are a proxy for prices on the
east side of the Idaho Power system.
The below table shows ICE daily HLH index price average ($/MWh).
Four
Year Month Mid-C Corners Palo Verde
2006 June 36.1 63.4 62.1
July 70.3 97.0 91.3
August 63.6 68.4 65.2
2007 June 52.2 72.7 70.7
July 64.1 86.0 81.9
August 61.1 75.8 70.5
2008 June 37.7 102.6 104.7
July 74.3 104.1 105.6
August 72.2 77.9 78.9
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 61
2009 June 22.1 28.6 29.1
July 35.6 41.3 39.7
August 38.2 36.7 34.1
2010 June 16.9 37.7 36.5
July 36.7 47.6 42.8
August 40.0 45.9 41.4
(e) The Eastside purchase wil likely be transacted in the wholesale energy
market during the 24 months prior to the energy need.
(f) The actual transmission path wil be identified at the time of the
transaction.
The response to this Request was prepared by Thomas A. Noll Ph.D., Senior
Planning Analyst, Idaho Power Company, and John Anderson, Manager, Power Supply
Operations Manager, Idaho Power Company, in consultation with Lisa D. Nordstrom,
Lead Counsel, Idaho Power Company.
DATED at Boise, Idaho, this 9th day of August 2011",
"'
N B. WILLIAMS
orney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 62
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 9th day of August 2011 I served a true and
correct copy of IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER
COMPANY upon the following named parties by the method indicated below, and
addressed to the following:
Commission Staff
Donald L. Howell, II
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
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_ Overnight Mail
FAX
-- Email Don.HoweIlØìpuc.idaho.gov
Karl T. Klein
Deputy Attorney General
Idaho Public Utilties Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
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FAX
-- Email KarI.KleinCãpuc.idaho.gov
Industrial Customers of Idaho Power
Peter J. Richardson
Gregory M. Adams
RICHARDSON & O'LEARY, PLLC
515 North 2ih Street
P.O. Box 7218
Boise, Idaho 83702
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-- Email peterØìrichardsonandoleary.com
gregØìrichardsonandoleary.com
Dr. Don Reading
Ben Johnson Associates, Inc.
6070 Hil Road
Boise, Idaho 83703
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-- Email dreadingØìmindspring.com
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
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-- Email eloØìracinelaw.net
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 63
Anthony Yankel
29814 Lake Road
Bay Vilage, Ohio 44140
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-2 Email tonyCãyankel.net
Kroger Co.
Kurt J. Boehm
BOEHM, KURTZ & LOWRY
36 East Seventh Street, Suite 1510
Cincinnati, Ohio 45202
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-2 Email kboehmcæBKLlawfrm.com
jrhcæbattisher.com
Kevin Higgins
Energy Strategies, LLC
215 South State Street, Suite 200
Salt Lake City, Utah 84111
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-2 Email khigginscæenergystrat.com
Micron Technology, Inc.
MaryV. York
HOLLAND & HART LLP
101 South Capital Boulevard, Suite 1400
Boise, Idaho 83702
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-2 Email myorkcæhollandhart.com
tnelsoncæhollandhart.com
madavidsoncæhollandhart.com
fschmidtcæhollandhart.com
Richard E. Malmgren .
Senior Assistant General Counsel
Micron Technology, Inc.
800 South Federal Way
Boise, Idaho 83716
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-2 Email remalmgrencæmicron.com
Department of Energy
Arthur Perry Bruder, Attorney-Advisor
United States Department of Energy
1000 Independence Avenue SW
Washington, DC 20585
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-2 Email Arthur.brudercæhg.doe.gov
Steven.portercæhg.doe.gov
IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 64
Dwight D. Etheridge
Exeter Associates, Inc.
5565 Sterrett Place, Suite 310
Columbia, Maryland 21044
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-l Email detheridgeCãexeterassociates.com
Community Action Partnership
Association of Idaho
Brad M. Purdy
Attorney at Law
2019 North 17th Street
Boise, Idaho 83702
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-l Email bmpurdyCãhotmail.com
Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street
P.O. Box 844
Boise, Idaho 83701
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-l Email bottoCãidahoconservation.org
Snake River Allance
Ken Miler
Snake River Allance
P.O. Box 1731
Boise,ldaho83701
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NW Energy Coalition
Nancy Hirsh, Policy Director
NW Energy Coalition
811 First Avenue, Suite 305
Seattle, Washington 98104
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IDAHO POWER COMPANY'S RESPONSE TO THE U.S. DOE'S THIRD
INTERROGATORIES AND PRODUCTION REQUESTS TO IDAHO POWER COMPANY - 65