20191106IPC to Staff 26-36 - Redacted.pdf

SEffi*.
DONOVAN E. WALKER
Lead Counsel
dwal [e-mail]
November 6, 2019
VIA HAND DELIVERY
Diane M. Hanian, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, ldaho 83714
Re Case No. IPC-E-19-14
Power Purchase Agreement with Jackpot Holdings, LLC - ldaho Power
Company's Response to the Third Production Request of the Commission
Staff
Dear Ms. Hanian:
Also enclosed are four (4) copies each of a non-confidential and confidential disk
containing information provided in response to Staff's production requests.
Ve yours,
(
onovan E. Walker
an lDAcoRP companyRECEIVED
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Enclosures
Enclosed for filing in the above matter please find an original and three (3) copies of
ldaho Power Company's REDACTED Response to the Third Production Request of the
Commission Staff. Also enclosed for filing are an original and three (3) copies of ldaho
Power Company's CONFIDENTIAL Response to Commission Staff's Production Request
No. 26.
lf you have any questions about the enclosed documents, please do not hesitate to
contact me.
ilb
DONOVAN E. WALKER (lSB No. 5921)
ldaho Power Company
1221 West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
N:CEiVED
l:! lii'i -5 Pll tr: h I
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER FOR APPROVAL OF A
POWER PURCHASE AGREEMENT WITH
JACKPOT HOLDINGS, LLC, FOR THE
SALE AND PURCHASE OF UP TO 220
MEGAWATTS OF RENEWABLE SOLAR
GENERATION
CASE NO. IPC.E_19-.14
IDAHO POWER COMPANY'S
REDACTED RESPONSE TO
THE THIRD PRODUCTION
REQUEST OF THE
COMMISSION STAFF
COMES NOW, ldaho Power Company ("ldaho Power'' or "Company''), and in
response to the Third Production Request of the Commission Staff to ldaho Power
Company dated October 30, 2019, herewith submits the following information:
IDAHO POWER COMPANY'S REOACTEO RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COIVIMISSION STAFF - 1
REQUEST NO. 26: Please provide and describe the input assumptions and
functionality for the AURORA LTCE that are different between the 24 WEcc-optimized
portfolios in the initial application and the latest 24 WECC-optimized portfolios,
Differences to include (but not limited to): (1) REC values for Jackpot Solar, (2)
transmission interconnection costs for Jackpot Solar, (3) removal of Franklin Solar, (4)
correct online date for Jackpot Solar, (6) allowing the model to correct the peak credit
for new solar if Jackpot Solar is not selected, and (7) change in the amount of excess
overbuilds beyond the planning reserve target.
RESPONSE TO REQUEST NO. 25:
(1) REC Values for Jackpot Solar
The renewable energy certificate ("REC") forecast for Jackpot Solar is discussed in
detail in the Company's response to Staffs Data Request No. 31. While these amounts
were initially excluded from the Company's analysis, in light of ldaho Power's
comprehensive review of all modeling inputs following Staff's submittal of Request No.
25 in this case, it was determined that potential REC revenues associated with the
contract should not have been excluded. Therefore, the current analysis includes
potential benefits associated with REC sales form the Jackpot Solar Project.
(2) Transmission lnterconnection Costs for Jackpot Solar
The transmission interconnection costs for Jackpot Solar are discussed in the
Company's Response to Staff s Data Request No. 31 , including a discussion of why
these amounts were not included in the Company's initial filing in this case.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 2
(3) Removal of Franklin Solar
On October 23, 2019, ldaho Power filed comments in this case updating the
Commission that on October 18, 2019, it delivered notice stating that the Company
elected not to exercise its right and option to purchase the 100 megawatts ('MW") of
Additional Output identified as Franklin Solar in Section 8.3.1 of the Power Purchase
Agreement ('PPA). As indicated in the comments, a number of factors conkibuted to
the Company's decision to not purchase the additional 100 MW of solar generation.
First, ldaho Power is concerned about adding intermittent and variable
generation beyond the 120 MW from the Jackpot Solar purchase. The most recent
integration study, conducted in 2017-2018, identified a 173 MW limit of additional
variable generation that the then current system configuration and load could integrate
without unacceptable reserve violations.
Second, the Company has received unsolicited offers since the filing of the
Jackpot Solar PPA that are lower than the combined Jackpot and Franklin price of
$23.11lmegawatt-hour ('MWh'), but not lower than the $21.7slMwh for the 120 MW of
Jackpot Solar.
Third, high-level discussions with existing and potential customers who are
interested in large solar and/or the direct purchase from ldaho Power of generation and
the renewable attributes of that generation require their purchase to be directly tied to
the incremental addition of such generation and are not interested in generation from an
already-committed resource.
Lastly, ldaho Power's credit rating agencies take an unfavorable view of
additional large PPA obligations, particularly those that are not required by law under
IDAHO POWER COMPANY'S REOACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 3
the Public Utility Regulatory Policies Act of 1978 (.PURPA). All PPA obligations, and
the imputed debt therefrom, are negatively viewed by the Company's credit agencies
and by many investors and can adversely impact the Company's credit rating, as well
as the overall financial health of the Company.
Because the Company elected to forego the incremental 100 MW associated
with the Franklin project, it was removed from the stack of available resources within the
Long-Term Capacity Expansion ("LTCE") model.
(4) Correct Online Date for Jackpot Solar
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 4
The current scheduled operating date for Jackpot Solar is December 1,2O22. ln
initial modeling runs, the selection of a 2022 operating year within the model resulted in
a scenario in which generation started at the beginning of the year, or eleven months
prior to the scheduled operating date indicated in the contract. To better align the
modeled online date with the expected online date from the contract, the modeled year
was adjusted lo 2023 wlth generation output starting January 1,2023, or one month
after the scheduled operating date.
lThe number 5 was omitted in Staffs initial reouestl
(6) Peak Capacitv Credit for Solar Resources
The solar peak-hour capacity credit on a by-project basis is provided in tabular
and graphic format on page 25 of the 2019 IRP Appendix C: Technical Report. ln the
initial application, Jackpot Solar comprised projects 1 through 3, Franklin Solar
comprised projects 4 and 5, and generic solar comprised projects 6 through 24. ln the
latest portfolios developed by AURORA, Franklin Solar was removed and generic solar
now comprises projects 4 through 24.
AURORA has the ability to individually model the capacity value for each project,
but these values are directly assigned. Therefore, if Jackpot is not selected, the values
for the other projects remain as assigned. The current version of AURORA lacks the
capability to dynamically adjust peak-hour solar capacity contributions when Jackpot is
not selected, but other solar resources are selected in later years. lt should be noted,
however, that the impact of this modeling limitation in AURORA is relatively small, as
the difference in capacity value between the average of projects 1-3 (Jackpot Solar)
and Project 4 (the next project in the queue) is only 2.9 MW (p 25, 2019 lntegrated
Resource Plan, Appendix C).
(7) Plannins Marqin Considerations
There was no modeling change within the LTCE model regarding excess builds
as they relate to planning margins. However, as discussed in subsection 10 below and
detailed in the Company's Response to Staffs Request No. 29, the Company took into
consideration the ability to modify portfolios with respect to planning margin through a
manual optimization process. This process is discussed in more detail below.
ln addition to the differences described above and referenced in Staff s request,
the following changes have been implemented for the latest 24 WECC-optimized
portfolios:
(8) Boardman-to-Heminqwav ("82H") Transmission Revenue Credits
For modeling purposes in the filed
transmission revenue credits associated
2019 lntegrated Resource
with B2H were excluded
Plan ("lRP"),
because the
Company initially felt that a conservative approach was appropriate for evaluating this
IDAHO POWER COIUPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF . 5
resource. These credits reflect the estimated incremental transmission wheeling
revenue from non-native load customers as a result of B2H.
However, through the Company's comprehensive re-evaluation of all inputs into its
Jackpot and IRP modeling runs, it determined that it is appropriate to include all relevant
cost and benefit information associated with each resource type, including incremental
transmission revenues from B2H. Therefore, the latest 24 WECC-optimized portfolios
now include these amounts, which is consistent with the methodology utilized in the
2017 rRP.
{9) Discount Rate Modification
IDAHO POWER COI\4PANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 6
The discount rate used to develop the latest 24 WECC-optimized portfolios was
reduced from 9.59% lo 7.12o/o, reflecting the after-tax weighted-average cost of capital
(.WACC). The original discount rate used in the 2019 IRP financial modeling utilized
the Company's WACC plus a tax gross-up for the equity-financed portion of the overall
costs. This represented a change from prior lRPs, in which the traditional WACC was
used for all discounting calculations. While both methods (pre-tax and posltax) are
reasonably considered and analytically sound, the Company believed the higher
discount rate may better align with the customer cost perspective, as it reflects the total
financing costs customers will actually pay through rates.
However, while conducting the supplemental IRP analyses following the filing of
the 2019 lRP, the Company observed that the use of the higher discount rate was
having a material impact on the timing and nature of investments included in the various
portfolio runs, particularly those portfolios modeled under expected case assumptions. lt
was not the Company's intent for the change in discount rate methodology to serve as a
major driver of changes to its long-term planning outcomes, especially at a time when
other significant modifications to the analytical framework were being implemented,
such as the introduction of computer-based LTCE modeling. As a result, the Company
has returned to the prior practice of applying its internal after-tax WACC as the discount
rate for the 2019 IRP until more evaluation and vetting of alternative methodologies can
occur. This approach remains consistent with prior years' lRPs and may be more
understandable as a general indicator of value in the near-term.
(10) Natural Gas Pipe line and Capacitv Considerations
While reviewing the modeling methodology, ldaho Power determined that certain
costs associated with the procurement of incremental natural gas supply should be
incorporated into the model; therefore, additional fixed costs associated with future
natural gas resources have been added.
To ensure pipeline transportation capacity will be available for future generation
needs, it is necessary to reserve capacity prior to a plant's in-service date. As a
reference point, ldaho Power examined the recent contract between lntermountain Gas
Company and Northwest Pipeline for the procurement of pipeline transportation. This
contract indicated a discount (25% of the fuli tariff rate of 39 cents) for the first five years
before transitioning to the full tariff rate for the remainder of the term. Based on this
contract, and after considering limited interest in the path that the Company would
require, ldaho Power applied a conservative estimate of 50% of the full tariff rate (19.5
cents) prior to a plant's in-service date, with full tariff applied thereafter. This reservation
fixed cost adder was applied to two 55.5 MW and two 111 MW reciprocating engines,
as well as two 300 MW combined cycle plants. These capacity limits were based on the
amount of generation the Company believes could be supplied by existing pipeline
infrastructure.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 7
Additional future natural gas capacity beyond the limits described above would
require an expansion on the Northwest Pipeline from the Rocky Mountain supply region
to ldaho. An expansion would provide diversification benefits from the current mix of
firm transportation, which consists of 60% from British Columbia, 40o/o from Alberta, and
no firm capacity from the Rocky Mountain supply region, Procuring firm capacity from a
third supply region would provide benefits to ldaho Power and its customers through
risk mitigation. New supply located to the east of ldaho Power's service area would
provide an additional pathway for gas procurement if service interruptions were to occur
to the north and/or west. Northwest Pipeline provided an expansion cost estimate of
lUtrlafU/day, which is the levelized cost for a 3O-year contract,
(1 1) Manual Optimization
Utilizing the 24 WECC-optimized portfolios, the Company has implemented an
additional step to manually refine WECC-optimized portfolios ensure that least-cost,
least-risk portfolios specific to ldaho Power's service area are evaluated in determining
the preferred portfolio for the 2019 lRP. The manual refinement targets adjustments in
timing to coal unit retirements as well as the timing associated with building additional,
future resources. The planning reserve margin is used as an initial measure to assure
that as manual portfolios are developed, resource adequacy is maintained. The manual
portfolios will then be evaluated alongside the 24 WECC-optimized portfolios to
determine the Company's preferred portfolio.
' The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTEO RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COIVIMISSION STAFF - 8
REQUEST NO. 27: Please provide a supplemental response to Staff Production
Request No. 2 that includes the information for the latest 24 WECC-optimized portfolios
RESPONSE TO REQUEST NO.27: The su pplemental data to Staffs Request
No. 2 is provided in Confidential Attachment 1 on the confidential CD and Attachment 2
on the nonconfidential CD. The confidential CD will be provided to those parties who
have executed the Protective Agreement in this matter.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COIVIMISSION STAFF - 9
REQUEST NO. 28: Please provide a NPV summary of the latest 24 WECC-
optimized portfolios similar to the "Portfolio Summaries" provided at the April 11, 2019
IRPAC meeting
RESPONSE T RE EST NO. 28: Please see the Attachment on the
nonconfidential CD for the requested information. While the Company has developed
all 24 WECC-optimized portfolios given time and resource constraints, ldaho Power has
not completed the cost runs under all four future scenarios lor all 24 portfolios. ln the
event that a scenario has not yet been completed, the cell in the attachment is blank.
The Company anticipates having the remaining model runs completed by Friday,
November 15th and will file this information as a supplement to this response.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF. ,10
REQUEST NO. 29: Please identify all WECC-optimized portfolios that have
been manually modified for this analysis, and provide: (1) all the manual modifications
made to the WECC-optimized portfolios, and (2) a NPV summary of the modified
portfolios similar to the "Portfolio Summaries" provided at the April 11, 2019 IRPAC
meeting.
RESPONSE TO REQUEST NO. 29:Please see the Company's Response to
Staffs Request No. 35.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COIUPANY'S REOACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMI/ISSION STAFF - ,I1
REQUEST NO. 30: Please provide the average monthly Mid-C electricity price
forecast for each hour of each day over a ten-year period (Dec. 2022-Dec
generated by Aurora in Excel format for the following alternative futures:
a. Zero COZ; planning gas; and
b. Planning CO2; planning gas.
RESPONSE TO REOUEST NO. 30:
2032)
a. Given time and resource constraints, ldaho Power is unable to provide the
requested information to 30(a) by November 6th. However, the Company's response to
Staff Request No. 32 contains a monthly summary of the Mid-C electricity prices under
zero CO2; planning gas. The Company anticipates having the requested information
completed by Friday, November 15th, and will file this information as a supplement to
this response.
b. Please see the attachment provided on the nonconfidential CD for the
requested information.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COIVIMISSION STAFF - 12
REQUEST NO. 31 : Please provide the workpapers used to create Exhibit No. 2
from Larkin's Direct Testimony
RESPONSE TO REQUEST NO. 31:Please see Attachment 1 provided on the
nonconfidential CD and Confidential Attachment 2 provided on the confidential CD. The
confidential CD will be provided to those parties who have executed the Protective
Agreement in this matter.
The response to this Request is sponsored by Matt Larkin, Revenue
Requirement Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTEO RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 13
REQUEST NO. 32: Please provide the monthly average Mid-C electricity price
forecast over a 20-year period (Dec. 2022-Nov. 2023) generated by Aurora in Excel
format for the following alternative futures:
a. Zero CO2: planning gas;
b. Planning CO2; planning gas;
c. High CO2; planning gas,
d. Planning CO2; mid gas; and
e. Planning CO2; high gas.
RESPONSE TO REQUEST NO. 32: Please see the attachment on the
nonconfidential CD for the requested information. Please note that per the Company's
telephone call with Commission Staff, the provided information covers the 20-year IRP
planning period of 2019-2038.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF . 14
REQUEST NO.33: Please provide a supplemental response to Staff Production
Request No. 16 that includes the REC values included in the updated analysis along
with workpapers for the calculation. ln addition, please address the following:
a. What information or data was used to determine the REC forecast used in
the analysis? Please provide the information and data.
b. What type of RECs are assumed? (Example: Bundled, Unbundled, etc.)
c. What market are the RECs assumed to be sold in?
d. Please provide the dollar value and type (Bundled, Unbundled, etc.) of
actual RECs the Company has sold over the last 3 years.
RESPONSE TO REQUEST NO. 33:
a - c: Please see Attachment 1 provided on the nonconfidential CD detailing the
calculation of the Renewable Energy Certificates ('REC) price forecast utilized in the
updated Jackpot Solar analysis. lt should be noted that this is the same forecast utilized
in the Company's 2019 lntegrated Resource Plan applied to all REC-generating
resources. Attachment 1 lists the types of RECs assumed as well as the various REC
markets utilized in the analysis. The Company has also added two columns to this
spreadsheet detailing the assumed generation from Jackpot applied to the REC price
forecast to determine total estimated REC revenues from Jackpot. The following
narrative details the Company's REC forecasting process:
ldaho Power's REC price forecast is based on a forecast of REC values in
various markets to which the Company has access. The REC market can be generally
divided into a compliance market, such as to fulfill a state Renewable Portfolio Standard
("RPS"), and a voluntary market, such as private companies wishing to be green in their
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 15
energy consumption or utility green power programs procuring RECs on behalf of their
retail customers. Due to liquidity issues, prices for RECs vary based on the nature of
each market. Currently, as in the past, the California RPS market is the premium
market offering the highest overall prices. Therefore, ldaho Power attempts to sell
RECs into the compliance markets as much as possible. However, due to market depth
issues, there are limits to how much the Company can sell into this premium market.
When there are still RECs remaining that the Company is unable to sell into California,
the RECs are sold to the next highest price market, such as the Washington RPS or
Green-e.
Attachment 1 details how the Company develops its forecast to reflect these
market conditions. Columns B through E reflect the current REC price forecast for
various markets provided by ClearEnergy, a REC brokerage firm. There are four REC
markets / types listed in these columns:
. CEC 83: Unbundled California Energy Commission ("CEC") RECs
r G/e WECC: Green-e Certified RECs for the WECC Region
. CEC 82: Bundled CEC RECs
o WA RPS: Washington State Renewable Portfolio Standard-Eligible RECs
Columns H through L then detail how this multi-market forecast is weighted by
the Company's assumed ability to sell into each of these markets. These weightings are
based on the Company's past experience with regard to the depth of each market, as
well as expected market depth in the future. As noted above, bundled RECs in
California (i.e., CEC 82) reflect the highest priced market, meaning this is the
Company's preferred option. This category has the highest weighting in the Company's
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 16
forecast (70%), followed by the next highest priced market for Washington RPS-
compliant RECs (20olo), with unbundled Green-e / CEC 83 RECs reflecting the lowest
priced market with the lowest percentage weighting (10%).
d: Please see Confidential Attachment 2 provided on the confidential CD
containing historical REC sale information for each year 2016 through 2018. The
confidential CD will be provided to those parties who have executed the Protective
Agreement in this matter.
The response to this Request is sponsored by Matt Larkin, Revenue
Requirement Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 17
REQUEST NO.34: Please provide the following information
a. Describe the new interconnection costs related to the Jackpot Solar PPA
that are included in the updated modeling inputs.
b. Why were they added?
c, Please explain why these costs are not the responsibility of the
developer/project owner.
d. Please provide the workpapers used to produce the interconnection inputs
in the model.
RESPONSE TO REQUEST NO. 34:
a. The interconnection costs and network upgrades related to Jackpot Solar
consist of installing a three-breaker ring-bus 345-kV class generation interconnection
substation including: protection, communications, and controls. The network upgrades
are described in detail in Confidential Attachment 1 provided on the confidential CD,
Based on this analysis, ldaho Power has included approximately $11 million in
Company-funded interconnection costs in its current Jackpot analyses, translating to a
levelized cost-per-kilowatt-per-month of $0.74.
b, Prior to the time that Jackpot Solar approached ldaho Power with a
proposal to sell its generation to ldaho Power, Jackpot Solar had completed the
interconnection study process as a non- PURPA, independent power producer pursuant
to the Open Access Transmission Tariff ("OATT"). The project was studied for
interconnection as an Energy Resource ("ER"), which looks only at required facilities
and upgrades needed to connect to ldaho Power's system, without looking at the
deliverability requirements or upgrades required to deliver its output to a particular
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 18
location or load. Such evaluation and/or studies would be done subsequently at the
time when the project made a request to deliver its output, as a poinlto-point
transmission service request, or if selling to ldaho Power as an ldaho Power Designated
Network Resource. Pursuant to its request, the project was initially studied as an ER
identlfying a new substation at the point of interconnection that connected to the
MidpointNV/lD Border 345-kV line in a tap configuration.
Jackpot subsequently approached ldaho Power proposing to sell the projects
output to ldaho Power, and ldaho Power eventually entered into a Power Purchase
Agreement ('PPA') with the developer, thus changing the status of the project and the
type of interconnection. Once ldaho Power had a contract to take the generation from
the project, it required ldaho Power's merchant function to submit a Transmission
Service Request for Network lntegration Transmission Service, which required the
project to be studied for the deliverability of its output as an ldaho Power Network
Resource ("NR"). The requested transmission service requires the transfer of the
project's energy across ldaho Power's internal transmission system to serve ldaho
Power's native load. As a result, and in order to provide the requested Network
lntegration Transmission Service, a more robust ring-bus configuration was required, as
opposed to the previously identified tap configuration for ER service, totaling
approximately $11 million in network upgrades in order to serve ldaho Power load as a
Designated Network Resource. Due to the project's status as a non-PURPA NR, the
identified Network Upgrades are funded by the Transmission Provider, ldaho Power
Transmission, as required by the OATT. This is the amount currently reflected in the
Company's analysis; this concept is discussed further in response to part c below.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 19
The System lmpact Study for network transmission service was completed on June 7,
2019, and ldaho Power and the project developers met to discuss the results.
Subsequently, ldaho Power sent a letter to the project developers memorializing that
discussion, which is Confidential Attachment 2 provided on the confidential CD. The
confidential CD will be provided to those parties who have executed the Protective
Agreement in this matter. The Facility Study for network transmission service was
completed and sent on October 7, 2019 and is provided as Confidential Attachment 1.
The confidential CD will be provided to those parties who have executed the Protective
Agreement in this matter.
c. The cost responsibility for network upgrades varies based on the type of
service requested and the status of the generator as PURPA or non-PURPA. When the
project initially applied for interconnection and was studied as an ER, the network
upgrades as an Open Access Transmission Tariff (''OATT") Generator lnterconnection
are generally funded by the interconnection customer and reimbursed by the
transmission provider with credits used to offset transmission service charges over time.
However, once the project contracted to sell all of its output to ldaho Power, ldaho
Power was required to request Network lntegration Transmission Service. The network
upgrades for the associated Network lntegration Transmission Service are funded by
the Transmission Provider pursuant to the OATT, which in this case is ldaho Power
Transmission. Therefore, these costs are appropriately included in the updated Jackpot
analysis, as they reflect a Company-funded investment in its transmission system.
d. The workpaper used to produce the interconnection inputs in the model is
included as Attachment 3 and provided on the nonconfidential CD. Please note that
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMIV1ISSION STAFF - 20
interconnection cost estimates vary over time as new information comes available and
analyses become more refined. Consequently, the cost estimates listed in Attachments
1 through 3 do not match exactly. The value of $10,595,973 listed in cell B37 of
Attachment 3 represents the amount included in the Company's Jackpot analyses,
reflecting the most current information available at the time these analyses were
performed from the Facility Study, Confidential Attachment 1.
The response to this Request is sponsored by Matt Larkin, Revenue
Requirement Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 21
REQUEST NO.35: Please provide the requested information in Attachment A,
which was discussed on October 28th, 2019, between ldaho Power and Commission
Staff as a supplement to Staff Production Request No. 25
RESPONSE TO REQUEST NO. 35: Please see the attachment provided on the
nonconfidential CD detailing analytical results from Sets 1 and 2 as detailed in Staffs
Attachment A. Per ldaho Power's email to Staff on October 29,2019, ldaho Power is
providing results that are currently available (Sets 1 and 2), and will provide the
remaining modeling runs (Set 3) as a supplemental response to this request no later
than November 15, 2019.
The ''NPV Summary'' tab contains the 20-year net present value ("NPV") cost
performance of each scenario, calculating the difference between the "with" and
"without" Jackpot scenarios. NPV's are specific to ldaho Power's service area.
The "Portfolios" tab contains the resource buildouts under each of the runs.
There are also notes at the bottom describing instances in which resource additions
were required in the manual process to ensure planning margin requirements were met.
The "Base" runs in this tab reflect the WECC-optimized results from the LTCE model.
Therefore, manual modifications can be determined by comparing the "Base" scenarios
to those listed to the right.
The response to this Request is sponsored by Kresta Davis-Butts, Resource
Planning and Operations Hydrology Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF - 22
REQUEST NO. 36: Please identify and explain the cause(s) driving the
difference between the results of Production Request No.25 provided to Staff in the
September 17, 2019 meeting and the results provided in the October 21 ,2019 meeting
between Staff and ldaho Power.
RESPONSE TO REOUEST NO.36: The numbers presented in the September
17, 2019, meeting reflected preliminary results from analyses developed in the early
stages of the Company's Response to StafFs Request No. 25. lt should be noted that
these figures were prelimanary in nature and were counterintuitive to the extent that they
led the Company to hold the September meeting with Staff and suspend the processing
of its 2019 IRP to further examine the modeling methodology. As a result of this
examination, between the September and October meetings, the Company made
several significant modeling improvements. The following list details key additions /
modifications to the October analysis that were not reflected in the September runs:
o lnclusion of REC benefits associated with generation from both Jackpot and
Franklin (as discussed in the Company's Response to Request No. 33);
o The cost associated with transmission upgrades required for the Jackpot Solar
Project (as discussed in more detail in the Company's Response to Request No.
34); and
. Movement to a non-grossed up discount rate of 7 ,12ok relalive to the 9.59%
grossed up rate utilized in the September model.
The Company views these changes as key improvements to the modeling
methodology, thus rendering the preliminary results presented at the September
meeting obsolete and invalid. lt should be noted that the first two bullet points above
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 23
(inclusion of REC benefits and transmission upgrades) were discussed at the
September meeting, but were not included in the numbers that were provided on that
date. lt should also be noted that the Company's Response to Staffs Request No. 26
provides additional modeling enhancements made after the October 21 ,2019 meeting.
The response to this Request is sponsored by Matt Larkin, Revenue
Requirement Manager, ldaho Power Company.
DATED at Boise, ldaho, this 6th day of November 2019.
OVAN E, WALKER
Attorney for ldaho Power Company
IDAHO POWER COIVIPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF .24
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 6th day of November 2019 I served a true and
correct copy of IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION STAFF upon the following
named parties by the method indicated below, and addressed to the following:
Commission Staff
Edward Jewell
Deputy Attorney General
ldaho Public Utilities Commission
472 West Washington Street (83702)
P.O. Box 83720
Boise, ldaho 837 20-007 4
X Hand Delivered
_U.S. Mail
_Overnight Mail
_FAXX Email edward. iewell@puc. idaho.qov
I
Kim rly Towel xecutive Assistant
IDAHO POWER COMPANY'S REDACTED RESPONSE TO THE
THIRD PRODUCTION REOUEST OF THE COMMISSION STAFF - 25