20201002IPC to Staff 13-26 - Redacted.pdf

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LISA D. NORDSTROT'
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October 2,2020
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg.8, Ste.201-A
Boise, ldaho 837204074
Re: Case No. IPC-E-20-30
ln the Matter of ldaho Power Company's Application for Authority to
Establish Tariff Schedule 68, Interconnections to Customer Distributed
Energy Resources
Dear Ms. Noriyuki:
Attached for electronic filing, pursuant to Order No. 34602, is ldaho Power
Company's Responses to Commission Staffs Second Produc'tion Request, Nos. 13
through 26.
lf you have any questions about the attached document, please do not hesitate to
contact me.
Very truly yours,
X;!(^*t,.*,
Lisa D. Nordstrom
LDN:slb
Enclosure
LISA D. NORDSTROM (lSB No. 5733)
ldaho Power Company
1221 West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: (208) 388€936
I nordstrom@ ida hooower. com
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO ESTABLISH TARIFF
SCHEDULE 68, INTERCONNECTIONS
TO CUSTOMER DISTRIBUTED
ENERGY RESOURCES.
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CASE NO. |PC-E-20-30
IDAHO POWER COMPANYS
RESPONSES TO COMMISSION
STAFF'S SECOND PRODUCTION
REQUEST
COMES NOW, ldaho Power Company ('ldaho Powef or'Company"), and in
response to the Second Production Request of the Commission Staff to ldaho Power
Company dated September 11,2020, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST . 1
REQUEST NO. 13: On page 19 of her direct testimony, Ms. Aschenbrenner
states that it is possible to identiff customers who have e:panded their system, or
cases when they may no longer be on-line, using Automated Metering Infrastructure
(AMl), and that this can be done at a significant cost savings relative to "rolling a truck.'
What is the cost savings to the Company if on-site recertification is removed? lnclude
with your response an Excelworkbook that shows the calculation.
RESPONSE TO REQUEST NO. 13: Please see Attachment 1 for the
workpaper quantiffing the costs of a recertification inspection. By removing the three-
year recertification requirement, ldaho Pourcr expects to reduce the number of
recertification inspections by approximately 80 percent per year, and based on current
projections (cited on page 19 of the direct filed testimony referenced), the Company
estimates it would avoid incurring costs for these recertifications of $112,924
(1,800*$78 .42*0.8) in 2021and $158,0(N (2,520*$78.42.0.81in 2022,
The response to this Request is sponsored by Connie Aschenbrenner, Rate
Design Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST -2
REQUEST NO. 14: PIease provide workpapers that were used to calculate the
retum trip charge of $81. Provide in excel format with formulas intac't.
RESPONSE TO REQUEST NO. 14: PIease see Attachment 1 for the
workpapers used to calculate the return trip charge of $61.
The response to this Request is sponsored by Connie Aschenbrenner, Rate
Design Senior Manager, ldaho Porer Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .3
REQUEST NO. 15: How many billing hours are needed to do a thorough on*ite
inspection prior to approval?
RESPONSE TO REQUEST NO. {5: Idaho Porverestimates one hourto
perform an on-site inspection, including travel, inspec'tion, and reporting. Please see
Attachment 1 for the supporting workpaper.
The response to this Request is sponsored by Connie Aschenbrenner, Rate
Design Senior Manager, ldaho Power Gompany
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST - 4
REQUEST NO. 16: Hon many employees are needed for an on-site inspec{ion?
What is the average loaded wage for an on-site inspec'tion?
RESPONSE TO REQUEST NO. t6: An on-site inspecilion requires one
employee and is typically performed by a Meter Technician. The average loaded wage
for a Meter Technician is cunently $68.48 per hour.
The response to this Request is sponsored by Connie Aschenbrenner, Rate
Design Senior Manager, ldaho Povuer Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST - 5
REQUEST ilO. 17: I/Vhat is the total mst of an on-site inspec'tion to Company,
including but not limited to, direct labor, indirect labor, all expenses, and the amount of
time per inspection?
RESPONSE TO REOUEST 1{O. f 7: Idaho Power estimates the direct costs
for an initial on-site inspection to be approximately $84. Please see Attachment 1 for
the workpaper that shoua the calculation of an initial on-site inspection cost.
The response to this Request is sponsored by Gonnie Aschenbrenner, Rate
Design Senior Manager, ldaho Poupr Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST - 6
REQUEST NO. f 8: What iE the cost of the sptem protection package described
on pages 17 and 27 of Mr. Ellsworth's direct testimony?
RESPONSE TO REQUEST NO. t8: Page 17 of Mr. Ellsworth's direct
testimony referenoes commercia! or industrial customers that installed distributed
energy resources ('DERs') behind the meter and in parallelwith the Company's system.
These systems nyere all less than 3 MVA, and only one required the installation of
protection equipment, which included a protective relay that cost approximately $2,000.
Page 27 ol Mr. Ellsworth's direct testimony references system protection
equipment for non-export DERs of 3 MVA or larger. The Company does not have an
example of a non-export system greater than 3 MVA to reference for cost, but an
engineering review would evaluate the type of equipment required, such as but not
limited to, disconnect switches, a reclosing device, or the type of protective relays. The
specific requirements and resulting components would be dependent on the system
details. ln totial, the Company estimates the equipment may cost approximately
$200,000, depending on the system details and system protection requirements
determined necessary.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .7
REQUEST NO. l9: ln reference to Section 2 of Schedule 68, Application
Process, please provide the workpapers and additional information, inctuding a
description, of how the $100 application fee was calculated. Also include within your
response the workpapers, notes, approvalfrom management, and any discussion within
the Company about the Schedule 68 proposed application fee.
RESPONSE TO REQUEST NO. t9: The 9100 apptication fee was approved
by the Commission in Case No. IPC-E-12-27, and is cunently included in Schedule 72.
Please see Attiachment 1 for a copy of ldaho Powe/s Response to Request No. 9 of the
ldaho Conservation League to ldaho Povver Company in Case No. IPC-E-12-27,dated
January 30, 2013.
Please reference Attachment 1 to the Company's Response to Request No. 20
to compare the total costs incurred to process applications to the application fees
collected in 2016 through 20'19. While the $100 application fee does not ofbet the
costs incurred to process the current leve! of applications, the Company did not request
an increase to the fee as part of this case.
The response to this Request is sponsored by Connie Aschenbrenner, Rate
Design Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECONDPRODUCTION REQUEST - 8
REOUEST NO. 20: Please provide the costs the Company incurs to process an
application. lnclude with your response an Exce! workpaper that includes, but is not
limited to, direct Iabor hours and cost, indirect labor hours and cost, and any other
related expenses.
RESPONSE TO REQUEST NO.20: Please see Attachment 1 for all direct
costs related to processing on-site generation applications. On the'Assumptions" tab of
Attachment 1, the Company has outlined the activities associated with processing an
application.
The response to this Request is sponsored by Connie Ascfienbrenner, RaE
Design Senior Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .9
REQUEST NO. 21: Please describe what takes place during a Feasibility,
System lmpact, and Facility Study and include time and cost estimates for these
proposed types of studies. Please include samples of these studies.
RESPONSE TO REQUEST NO. 2l: Feasibilitv Studv: The Feasibility Study
includes a general review of system impact and potential issues and includes
identification of any circuit breaker capabitity limits exceeded as a result of the
interconnection, identification of any voltage limit violations resulting from the
interconnection, identification of system protection adjustnents that are neoessary and
non-binding estimated cost of facilities requircd to interconnect the DER and address
any identified short circuit and pourer flow issues.
The Feasibility Study is completed by a Transmission & Distribution Engineer(s),
and actualtime will vary depending on the project's complexity. As proposed in
Schedule 68, the applicant pays a $1,000 application fee, which is intended to cover the
Feasibility Review cost. Barring unusual circumstances, the Feasibility Study will be
completed within 15 business days.
Svstem lmpact Study: The System lmpact Study provides a detailed
assessment of the transmission and distribution system adequacy to accommodate
higher complexity projects. A System lmpact Study consists of a short circuit analysis,
a stability analysis, voltage drop and flicker studies, protection and setpoint coordination
studies, and grounding reviews, as necessary. The System lmpact Study is completed
by a Transmission & Distribution Planning Engineer(s), and the actualtime willvary
depending on the project's complexity. This study may not be required for some
projects depending on size and location. A deposit ($2,000 for distribution and $10,000
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST - 10
for transmission) will be required from the applicant. The applicant must pay any study
costs that exceed the deposit, and if the deposit exceeds the invoiced fues, the
remainder is refunded.
A distribution System lmpad Study, if required, willbe completed and the results
transmitted to the applicant within 30 Business Days of execution of a System lmpact
Study Agreement.
A transmission System lmpact Study, if required, will be completed and the
results transmitted to the applicant within 45 Business Days of execution of a System
lmpact Study Agreement.
Facilitv Studv: The Facility Study includes design and engineering studies to
determine design and specifications. The Facility Study specifies and estimates the
cost of the equipment, engineering, procurement, and constructlon work (including
overheads) needed to implement the conclusions of the Feasibility and/or System
lmpact Study. Construction options are provided to the customer. A Project Leader
completes the Facility Study and the actualtime willvary depending on the complexity
of the project. A deposit of five perent of the estimated cost determined in the
Feasibility Study or System lmpact Study, not to exceed $30,000, would be required.
Any study fees will be based on the actual @sts, invoiced to the applicant after the
study is completed and delivered, and will include a summary of professionaltime. The
applicant must pay any study costs that exceed the deposit, and if the deposit exceeds
the invoiced fees, the remainder will be refunded.
In cases where distribution or transmission upgrades are required, the Facilities
Study will be completed within 45 Business Days after the applicant agrees to the
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .11
Facility Study. ln cases where no upgrades are neoessary, and the required facilities
are limited to local facilities at or near the applicant's point of inbrconnection, the
Facility Study will be completed within 30 Business Days after execution of the Facility
Study agreement.
Please note, while none of these studies have yet been completed for a
customer installing on-site generation, the Company has completed these types of
studies for non-utility Sellers interconnecting to the Company's system. For examples
of a Feasibility Study, System lmpact Study, and Facility Study completed, please see
the Attachment Nos. I - 3.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .12
REQUEST NO. 22: Please explain the Company's rationale for not requiring
existing customers to install smart inverters. Does the Company foresee any problems
that could occur because some Schedule 68 customers are using smart inverters and
others are using non-smart inverters?
RESPONSE TO REQUEST NO.22: Before interconnecting any of the
existing DERs, a study prooess was completed to determine what, if any, system
upgrades would be necessary to mitigate expected voltage impacts caused by the DER.
Requiring those same customers to prematurely replace their existing inverter would
impose unneoessary costs on the customer. As noted on page 15 of Mr. Ellsworth's
direct filed testimony, once a customer replaces an inverter, they will be required to
install an inverter compliant with the terms of Schedule 68, or a suooessor schedule, in
place at that time.
The Company does not foresee any problems that could occur because some
customergenerators use smart inverters and others use non-smart inverters.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
TDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SEGOND
PRODUCTION REQUEST . 13
REQUEST NO. 23: How does the Company foresee compensating customers
with Smart lnverter technology that can provide distribution grid benefits?
RESPONSE TO REQUEST NO. 23: The Smart lnverter technology being
enabled through the proposed Sclredule 68 requirements does not add incremental
benefit beyond that which would exist without the DER presene. The proposed Smart
lnverter configurable functions would allow for voltage/reactive po,yer control, low
voltage ride through, and anti-islanding settings. The DER creates the voltage
deviation, and it is the DER that can cost-effectively mitigate the deviation through the
installation of a Smart lnverter. Without a voltage-reactive power setting, a non+xport
system would still cause voltage issues at the custome/s site, or to adjacent customers,
that would have to be addressed through system upgrades, funded by the customer-
generator, absent the Smart lnverter capability.
The response to this Request is sponsorcd by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST .14
REQUEST NO. 24: Whatwillthe Gompany do (or require) as Smart lnverter
variables and standards change?
RESPONSE TO REQUEST NO. 24: The Company expects the variables
adopted through this process will meet the needs of our customers, and the grid, unti!
there is a significant increase in DER penetration. The Company will monilor revisions
to the IEEE 1547 standard to determine if future revisions warrant implementation to
address potential grid issues that materialize or assist in further increased DER
penetration. lf the Company does determine that difierent strandards should be required
for ldaho Power interconnections, the Company will seek approvalfrom the
Commission to implement changes to Schedule 68.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST . 15
REOUEST NO.25: Does the Company have any plans to implement IEEE 1547
communications protocols that would enable it to cornmunicate with customer generator
smart inverters? Please explain why orwhy not.
RESPONSE TO REQUEST NO. 25: No. Given the relatively low level of
DER penetration on ldaho Pone/s system, the Company did not consider proposing
additional func{ionality that would be implemented at what could be an additional
expense to customer generators.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO COMMISSION STAFF'S SECOND
PRODUCTION REQUEST - 16
REQUEST NO. 26: Please explain howthe Company intends to manage and
modify smart inverter reactive power and ride through settings in the event that high
DER penetration rates risk causing instabili$ in portions of its grid.
RESPONSE TO REQUEST NO. 26: The settings identified in the proposed
Schedule 68 include settings that are within the range of the IEEE 1il7 standard. That
standard was vefted to ensure that high penetration of DER would not have an adverse
effect on the grid. ln addition, the seftings in the proposal include the disturbance ride-
through requirement settings (Category lll) recommended by the North American
Electrical Reliability Corporation (NERC) for grid stability. However, as more
experience is gained by the industry, setting changes may be identified that will befter
serve the grid. At that time, the Company will determine if those changes should be
incorporated in the connected DER, and at what level.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, ldaho Power Company.
Respectfully submitted this 2d day of October, 2020
X; !7("*+--*,
LISA D. NORDSTROM
Aftorney for ldaho Power Company
IDAHO POWER COMPANY'S RESPONSES TO COMMISS]ON STAFF'S SECOND
PRODUCTION REQUEST - 17
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 2d day of October 2O2O,l served a true and
correct copy of IDAHO POWER COMPANY'S RESPONSES TO STAFF'S SECOND
PRODUCTION REQUEST upon the bllowing 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 8372A-OOT 4
ldaho Gonservatlon League
Benjamin J. Otto
ldaho Gonservation League
710 North 6h Street
Boise, ldaho 83702
ldaho Sierra Club
Lisa Young
Mike Heckler
503 W Franklin Street
Boise, ldaho 83702
ldaho Clean Energy Assoclation, !nc.
("lGEA')
Preston N. Garter
Givens Pursley LLP
601 West Bannock Street
Boise, ldaho 83702
Hand Delivered
_U.S. Mail
_Overnight Mail_Fru(_FTP SiteX Email [e-mail]
Hand Delivered
U.S. Mail
_Overnight Mail_FA)(_FTP SiteX Email [e-mail]
_Hand Delivered
U.S. Mail
Overnight Mail
_FA)(_FTP SiteX Email [e-mail];
michael. p. [e-mail]
_Hand Delivered
U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email prestoncarter@oivensoursley,com;
kend rah@o ivensp u rslev. com
Stephanie L. Buckner
Executive Assistant
IDAHO POWER COMPANY'S RESPONSES TO COMMISSTON STAFF'S SECOND
PRODUCTION REQUEST . 18
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 1 TO REQUEST NO. 13
(EXCEL SPREA DSHEET ATTACHED TO EMAILI
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 1 TO REQUEST NO.14
(EXCEL SPREADSHEET ATTACHED TO EMAILI
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SEGOND PRODUCTION REQUEST
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 1 TO REQUEST NO. 15
(EXCEL SPREA DSHEET ATTACHED TO EMAILI
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTAGHMENT 1 TO REQUEST NO.17
(EXCEL SPREADSHEET ATTACHED TO EMAILI
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
BEFORE THE
IDAHO PUBLIC UTILITIES GOMMISSION
CASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTAGHMENT 1 TO REQUEST NO. 19
TO
IDAHO POWER GOMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
REQUEST 1{O. 9: Please reEr to Exhibit 4 at page 40, which is a tegislative
format of the proposed revisions to Schedule 72. Please document horr ldaho power
calculated the $100 application fee for new Net Metering customers.
RESPONSE TO REQUEST NO. 9: The 9100 application fee is intended to
reflect cosE associated with the application prooess, including customer service,
internal administration, distribution feasibility research, and field visit and inspection
requirements. While the Company feels this charge is commensurate to the services
provided throughout the application process, it has not preparcd a study that specifically
delineates each of these costs.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst ll, ldaho Power Company, in consultiation with Lisa D. Nordstrom, Lead
Counsel, ldaho Power Company.
IDAHO POWER COMPANYS RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE IDAHO CONSERVATION LEAGUE TO IDAI{O POWER COMPANY - 15
BEFORE THE
IDAHO PUBLIG UTILITIES COMMISSION
cAsE No. lPc-E-20-30
IDAHO POWER COMPANY
ATTAGHMENT 1 TO REQUEST NO.2O
(EXCEL SPREA DSHEET ATTACHED TO EMAILI
TO
IDAHO POWER GOMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 1 TO REQUEST NO.21
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SEGOND PRODUCTION REQUEST
GENERATOR INTERCOI\INECTION
FEASIBILITY STUDY RBPORT
for integration of the proposed
3MW
IPC PROJECT QUEIJE, #520
to the
IDAIIO POWER COMPANTY ELECTRICAL SYSTEM
for
r
REPORT v.0
February 28,2017
OFFICIAL USE ONLY
This report contains Idaho Power Company Critical Energy Infrastnrsture lnformation
(CEID. Distribution of this report must be limited to parties that have entercd into a non-
disclosure agreement with ldaho Power Company and have a need to know.
Drte Revirion Initials of
02D8t2016 0 PMA FeSRGI #520-Original issue.
Revision History
3MW
Feasibility Study Report i
OFFICIAL USE ONLY
This report contains Idaho Power Company Critical Energy Infraskuctuir Information
(CEID. Distribution ofthis report must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.
Table of Contents
5.0 Description of Transmission Facilities 3
6.0 Description of Substation Facilities 3
?.0 Description of Distribution Facilities ......................... 3
8.0 Short Circuit Study Resu1ts.................. ....................... 3
9.0 Description of Required Facility Upgrades '..............4
10.0 Description of Operating Requirements .......--.......... 5
I1.0 Conclusion ........7
APPENDIX A................ ..................8
A-1.0 Method of Study.....
A-2.0 Acceptability Criteria
A-3.0 Grounding f}rirlqnen
A-4.0 Electrical System Protection Guidancc
B-1.0 Project #520 Site location..... ............... l0
3MW
Foasibility Study Report ii
OFFICIAL USE ONLY
This rcport contains Idaho Power Company Critical Energy Infrastructure Information
(CEII). Distribution ofthis report must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.
I
8
9
9
List of Tables
Table I Conceptual-level Cost Estimate for GI #520 4
List of F'igures
Figure I Operating requirements .......................6
Figure 2 Location ofE GI #520...... ............ l0
3MW
Fcasibility Study Report iii
OFFICIAL USE ONLY
This report contains ldaho Power Company Critioal Energy Infrastructure Information
(CEII). Distribution of this report must be limited to parties that have entered into a non-
disclosure agreement with ldatro Power Company and have a need to know.
1.0 Introduction
Eras contracted with ldaho Power Company (IPC) to perform a Generator
Interconnection Feasibilif Study forthe integration of the proposed 3 MW
I (the Project). The Project is located in IPC's Western Region
in Malheur County, Oregon (Sm Figure 2: Location of GI # 520 in Appendix
B). The project latitude and longitude are approximately
Generation Interconnect queue number 520 (GI #520').
The Project is
The Project has applied to connect to the ldaho Power distribution system for an injection of 3
MW at a single Point of lnterconnection (POI) at 12.47 kilovolts (kV). The POI is located in the
Ontario (ONTO) 024 distribution feeder boundary ONTO
substation. The POI latitude and longitude are approximately
This report documents the basis for and the results of this feasibility study for the GI #520
Generation Interconnection Customer. The report describes the proposed project the
determination of project interconnection feasibility and estimated costs for integration of the
Project to the Idaho Power System. This report satisfies the feasibility study requirements of the
Idaho Power Tariff.
2.0 Summary
The feasibility of interconnecting the 3 MW
024 distribution feeder was evaluated. The POI is located at
The power flow analysis indicated that interconnecting the
is feasible with modifications discussed in this report.
to [PC's 12.47 kV ONTO-
to ONTO-024
The Project will be required to control voltage in accordance with a voltage schedule as provided
by Idaho Power Grid Operations. Therefore, GI #520 will be required to install a plant conftoller
for managing the real and rcactive power output of the 3 MW inverter array at the project POL
Also, the installation of a phasor measur€ment unit device (PMU) at the POI and the installation
and maintenance costs associated with communication circuits needed to stream PMU data will
be required in order to interconnect GI #520.
A Transmission System Impact Study is required to determine if any additional network
upgrades arc required to integrate the Project into the IPC transmission system and to evaluate
system impacts such as thermal, voltage, transient stability, and reactive margin. Generator
interconnection service, either as an Energy Resource or a Network Resoutce, does not in any
way convey any right to deliver electricity to any specific customer or point of delivery.
3Mw-
Feasibility Study Report I
OFFICIAL USE ONLY
This report contains ldaho Power Company Critical Energy Infrastructure lnformation
(CEII). Distribution ofthis r€port must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.
Additionally, a Distribution System Impact Study will be required.
The total preliminary cost estimate to interconnect the the oNTo-024
distribution fbeder is $849,816, and includes the following tasks:r Install a four-pole 12.47 kY generation interconnection paokage at the PrOt. This includes
an SEL-421 protective relay, which requires 3-phase potential transformers (PTs), 3-
phase current transformers (CTs), and remote connectivity. Additionally, a single-phase
PT shall be installed on the interconnect customer side of the IPC reoloser,o Reconductor approximately 2.25 miles from the POI
-from
#4 ACSRto 795 AAC.o Replace recloser ONTO24R70X with an electronic rccloser. Additionally, a single-phase
PT shall be installed on the interconnect customer side of the recloser for deadline check.r Install a PMU device at the POI.o Install a single-phase PT and wiring for dead-line check on ONTO-024.o Install Beckwith M2001-D load tap changer (LTC) controllers on the Tl34 transformer at
ONTO substation.. Upgrade the ONTO T022 AMI transformer.
The cost estimate includes direct equipment and installation labor costs, indirect labor costs and
general overheads, and a contingency allowance. These arc cost estimates only and final charges
to the customer will be based on the actual construction costs inourred. It should be noted that the
preliminary cost estimate of $849,816 does not include the cost of the customer's owned
equipment to constuct the solar generation site or required communication circuits.
3.0 Scope of Interconnection Feasibility Study
The Interconneotion Feasibility Study was done and prepared in aocordance with tdaho Power
Company Standard Generator Interconnection Procedures to provide a preliminary evaluation of
the feasibility of the interconnection of the pnrposed generating project to the Idaho Power
system. As listed in the Interconnection Feasibility Study agreement, the Interconnection
Feasibility Study report provides the following information:o preliminary identification of any circuit breaker short circuit capability limits exceeded as
a result ofthe interconnection;o preliminary identification of any thermal overload or voltage limit violations resulting
from the interconnection; andr preliminary description and non-binding estimated cost of facilities rcquired to
interconnect the Small Generating Faoility to the IPC system and to address the identified
short circuit and power flow issues.
All other proposed generation projects prior to the Project in the Generator Interconnect queue
were considered in this study. A current list of these projects can be found in the Generation
Interconnection folder located on the Idaho Power web site at the link shown below:3Mw-
Feasibility Study Report 2
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This report contains Idaho Power Company Critical Energy Infrastructure [nformation
(CEII). Distribution of this report must be limited to parties that have entered into a non-
disclosure agreement with ldaho Power Company and have a need to know.
htto:/hvww.oatioasis.com/inco/indexhtml.
4.0 Description of Proposed Generating Project
GI #520, consists of a single 3 MW photovoltaic solar plant which requested to
be connected to ldaho Power's 12.47 kY ONTO-024 distribution feeder. The Project will need to
install a grid connection control system for managing the real and reactive power output of the
verters. The design drawing shows sets off
fused disconnects to step-
up the voltage from 480 V to 12.00 kV. The solar plant will need to size the step-up transformers
appropriately for the total plant MVA as well as the 12.47 kV connection. Additionally, the
design drawing shows grounded wye delta transformers. Idatro Power will require grounded wye
grounded wye or wye grounded wye with the ground on the utility side. The project will use !
photovoltaio modules per inverter, for a total
-
The Project's projected in-service date was not inoluded in the GI application.
5.0 llescription of Transmi$ion Facilities
Preliminary power flow analysis indicated that interconnection of a 3 MW injection at the POI
considered in this study is feasible. A Transmission System Impact Study will be requircd to
determine the specific network upgrades required to integrate the full project output of 3 MW.
6.0 Description of Substation Facilities
Idaho Power's ONTO substation is located in Malheur County, Oregon, The existing substation
transformer, ONTO T134, is a three-phase 138-13.09 kV transformer rated for 30 MVA.
7.0 Description of Distribution Facilities
The requested POI for the Project is on the ONTO-024 distribution fbeder. This is a grounded-
wye feeder operating at 12.47 kV at the POt. The Project must have a grounded-wye transformer
connection on the IPC side, as well as a wye connection on the Project side of the fansformer.
Refer to Appendix A, Section 3, for additional grounding requirernents.
8.0 Short Circuit Study Results
The fault cun€nt contribution from the PV generators does not exceed any circuit bneaker rating.
3Mw-
Feasibility Study Report 3
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9.0 Description of Required Facility Upgrades
The Project will be required to provide a plant contoller that will operate the inverter system in
Volt/VAr control mode in order to regulate voltage accoding to a voltage schedule that will be
provided by Idaho Power.
A Distribution System Impact Study will be requircd to evaluate distribution operational
concerns, mitigation options, and costs if the Project chooses to continue to the next phase of the
study process. Additionally, a Transmission System tmpact Study will be required to determine
the specific network upgrades required to integrate the full project output of 3 MW. The cost of
potential system upgrades would be determined during the Transmission System tmpact Study
and have not been included in the Feasibility Study cost estimate.
The following upgrades will be required to lPC-owned facilities to facilitate the interconnection
ofGI #520:o Install a four-pole 12.47 kV generation interconnection package at the POI. This includes
an SEL42I protective relay, which requires 3-phase potential transformers (PTs), 3-
phase current bansformers (CTs), and remote connectivity. Additionally, a single-phase
PT shall be installed on the interronnect customer side of the IPC recloser.o Reconductor apprcximatcly 2.25 miles from the POI
Epm#4ACSRto 795 AAC.o Replace recloser ONTO24R70X with an electronic recloser. Additionally, a single-phase
PT shall be installed on the interconnect customer side of the rccloser for deadline check.o Install a PMU device at the POI.o Install a single-phase PT and wiring for deadJine check on ONTG024.o Install Beckwith M2001-D load tap changer (LTC) conhollers on the Tl34 transformer at
ONTO substation.. Upgrade the ONTO T022 AMI transformer.
See the conceptual-level cost estimate in Table l.
Table I Conceptual-level Cost Estimate for GI #520
Item of Work Estimate
Generation interconnection and protection package
Substation upgrades
Distribution upgrades
Transmission upgades
$174,000
$5,800
$464,000
TBD in SIS
Unloaded costs
Contingency 2oo/o (l)
643,E00
$128,760
Total unloaded costs $772,560
3MW
Fcasibility Study Report 4
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(CEII). Distribution of this rcport must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.
Overheads (2)$77,256
Total loaded costs $849,815
$149"816TotalCost Estimate in 2015 dollers (3)
fied design
components, material cost incrcases, labor estimate shortfalls, etc.
(2) Overhead costs oovcr thc indircct costs ssrccided with thc Projecl
tS) fhir cost estimate includes direct equipment, material, labor, overhesds, and contingency as shown'
o Note that these estimates do not include the cost of the customer's oquipment/facilities or
required communication circuits for SCADA, PMU, and metering'
r Note that the overhead rates arc subject to change during the year.
o These are estimated costs only and final charges to the customer will be based on the
actual construotion costs incuned.
. These are non-binding conceptual level cost estimates that will be furtherrpfined upon
the request and completion of Transmission and Distribution Facility Studies.
10.0 Description of Operating Requirements
The project shall be oapable of injecting reactive power (over-excited) and absorbing reactive
power (under-excited) iqual to 145 MVAR at all active power output between 2Wo and l00o/o
of nameplate aotive Power rating.
3MW
Feasibility Study Report 5
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(CEID. birtribution of this report must be limited to parties that have entered into a non-
disclosure agreement with ldaho Power Company and have a need to know.
a
Qlnlcctino
-QAIEoru.E
PF = 0.9 (over-excited)
Flgure I Operrtlng requlrcmcnts
Idaho Power has determined that the inverter seleoted by the Project me€ts the r€active power
capability requir€ments.
The Project will be required to control voltage in accordance with a voltage schedule as provided
by Idatro Powq Grid Operations. Thcreforc, GI #520 will be required to install a plant contoller
for managing the real and reactive power output of the 3 MW inverter aray at the project POL
The installation of a PMU at the POI and maintenance costs associated with communication
circuits needed to strcam PMU data will also be required in order to interconnect GI #520.
Voltage flicker at startup and during operation will be limited to less than 5%o as measured at the
POI. The allowable voltage flicker limit is further rcduced during operation due to multiple
voltage fluctuations per hour or minute, per Idaho Power's T&D Advisory Information Manual.
The Project is required to comply with the applicable voltage fluctuation limits found in IEEE
Standard 1453-20A4IEEE Recommended Practicefor Measurement and Limits of Yohoge
Fluctuotions and Associated Light Flicker onAC Power Systems.
3Mw-
Feasibility Study Report 6
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This report contains Idatro Power Company Critical Energy Infrastructure Information
(CEID. Distribution ofthis report must be limited to parties that have entened into a non-
disclosure agreement with Idaho Power Company and have a need to know.
I
II
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PF = 0.9 (under-elalted)
The project is requircd to comply with the applicable Volage and Cunent Distortion Limits
founa in IEEE Standard 519-2014 IEEE Recommended Practices and Requirementsfor
Harmonic Control in Electical Powet fistems.
Additional operating requirements for the Project may be identified in the System Impact Study
when it is performed.
11.0 Conclusion
The requested interconnection of the GI #520, to Idaho Pow€r's sYstem
was studied. The project will need to interconnect using a 12.47 kV grounded-wye connection to
the ONTO-024 12.47 kV distribution feeder. The results of this study work confirm that it is
feasible to interoonnect the GI #520, to the existing ldaho Power system
with the modifications listed. A four-pole generation interconnect paokage, a PMU, dead-line
check, and a digital tap changer controls on the ONTO Tl34 are required to integrate the 3 MW
projeot as well as reconductoring approximately 2.25 miles from the POII
from #4 ACSRto 795 AAC and replacing recloser
ONTO24R70X withan elechonic rccloser.Additionally, a single-phase PT shall be installed on
the interconnect customer side of ONTO24RTOX for deadline check. A Transmission and
Distribution System tmpact Study is required to determine the specific transmission network
upgrades required to integrate the project as a Networ*. Resource and to evaluate the system
impacts sucli as thermal overload, voltage, transient stability, and reactive margin.
All generation projects in the area ahead of the Project in the IPC generation interconnection
qu.ir and theii associated transmission system improvements were modelod in a preliminary
jo*". flow analysis to evaluate the feasibility of interconnecting GI #520. The results and
lonclusions of this feasibility study are based on the realization of these projects in the unique
queue/project order.
The estimated cost to interconnect GI #520 to the IPC system ctthe 12.47 kV point of
interconnection considered in this study is approximately $849'816.
Generator interconnection service, either as an Energy Resource or a Network Resource, does
not in any way convey any right to deliver electricity to any specific customer or point of
delivery.-Transmission requirements to integrate the Project will be determined during the
System Impact Study phase of the generator intersonneotion prccess.
3Mw-
7Feasibilitv studv Rcport
.FFICIAL usE oNLy
This report contains Idaho Power Company Critical Energy Infrastructure lnformation
(CEII). bistribution of this r€port must be limited to parties that have entered into a non-
disclosurr agreement with Idaho Power Company and have a need to know.
APPENDD( A
A-1.0 Method of Study
The Feasibility Study plan inserts the hoject up to the ma;<imum rcquested injection into the
selected Western Electric Coordinating Council (WECC) power flow case and then, using Power
World Simulator or GE's Positive Sequence Load Flow (PSLF) analysis tool, the impacts of the
new l€sounc,e on Idaho Power's transmission system (lines, transformers, etc.) within the study
area are analyzed. The WECC and ldaho Power reliability criteria and ldaho Power operating
procedures werc used to determine the acceptability of the configurations considered. For
distribution feeder analysis, Idalro Power utilizes Advantica's SynerGEE Software.
A-2.0 Acceptability Criteria
The following acceptability criteria were used in the power flow analysis to determine under
which system configuration modifications may be required:
The continuous rating of equipment is assumed to be the normal thermal rating ofthe
equipment. This rating will be as determined by the manufacturer of the equipment or as
determined by ldatro Power. Less than or equal to 100% of continuous rating is
acceptable.
Idatro Power's Voltage Operating Guidelines were used to determinE voltage
requirements on the system. This states, in part, that distribution voltagos, under normal
operating conditions, are to be maintained within plus or minus 5% (0.05 per unit) of
nominal everywhere on the feeder. Therefore, voltages greater than or equal to 0,95 pu
voltage and less than or equal to 1.05 pu voltage are acceptable.
Voltage flicker during starting or stopping the generator is limited ta sYo as measured at
the point of interconnection, per ldatro Power's T&D Advisory Information Manual.
Idaho Power's Reliability Criteria for System Planning was used to determine proper
transmission system operation.
All customer generation must meet IEEE 519 and ANSI C84.1 Strndards.
All other applicable national and Idatro Power standards and prudent utility practices
were used to determine the acceptability of the configurations considered.
The stable operation of the system requires an adequate supply of volt-amperes reactive
(VAr or VArs) to maintain a stable voltage profile under both steady-state and dynamic
JMW
Feasibility Study Report E
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This report contains ldaho Power Company Critical Energy Infrastructure [nformation
(CEID. Distribution of this report must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.
system conditions. An inadequate supply of VArs will result in voltage decay or even
collapse under the worst conditions.
EquipmenUline/path ratings used will be those that are in use at the time ofthe study or that arc
represented by IPC upgrade projects that are either cuncntly under construction or whose
budgets have been approved for constuction in the near firture. Al[ other potential future ratings
are outside the scope of this study. Future transmission changes may, however, affect current
facility ratings used in the study.
A-3.0 GroundingGuidance
IPC requires interconnected transformers on the distribution system to limit their ground fault
curent to 20 amps at the Point of Interconnection.
A4.0 Electrical System Protectton Guidance
IFC requires electrical system protection per Requirements for Gencration Interconnections
found on the ldaho Power Web site,
htto://www.idahonower.comhdfs/BusincscToBusineca[ecilitvRcouirements.ndf
3Mw-
Feasibility Study Report 9
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(CEII). Distribution ofthis report must be limited to parties that have entered into a non'
disclosure agreement with ldaho Power Company and have a need to know.
APPENDIX B
B-1.0
-GI
Project #520 Site Location
3MW
Feasibility Study Report l0
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(CEII). Distribution of this report must be limited to parties that have entercd into a non-
disclosure agreement with ldaho Power Company and have a need to know.
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 2TO REQUEST NO.20
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION RESUEST
An IDACOnP CstrgtY
Final
Generator Interconnection
Facitity Study Report
for the
Project #435
for
ln
Idaho
November 13,2015
DRAFT - FACILITY STUDY REPORT (FSR)
Project Generation Queue #1435
November 13,2015
1. General Facility Description
("Seller') has stated that the proposed project will consist of a solar
photovoltaic array to located in Mountain Home, Idaho. The solar generation array is to connect
to Idatro Power Company (IPC)'s 69 kV hansmission line. The
total project output as studied is 20 MW.
Contact Information for Seller is as follows:
-
The Seller's photovoltaic system will be constructed as follows:l. The inverter system will comprise
inverter having an appar€nt power
with each
2.inverter stations will inverter step up
transformer with a 406
3. There will be aIMVA Generator Step Up (GSU) transformer with a 34.5 kV grounded-
wye to 69 kV grounded-wye rating.
4. A plant controller will be used to contncl the inverter system and to implement smart
inverter functionality for operating the project within a voltage range and power factor
specified by IPC at the point of interconnection.
The above referenced inverters, or equivalent inverters that have the same specifications and
functionality as stated above must be utilized. If a different inverter is utilized that has different
specifications and functionality than that which was studied then additional study and/or equipment
may be necessary.
A Standard Generator Interconnection Agreement (the '.GIA") under IPC's Open Access
Transmission Tariff (OA'fD or Schedule 72 between Seller and tPC - Delivery (Transmission
Owner) for the- Project, specifically Generator Interconnection Project #435'
willbeprepare@GIAwillbeadefinitiveagreementthatcontainstermsand
conditions that supersedes this FSR.
If an earlier queue project that is responsible for providing additional sub-transmission capacity
should drop out of the queue, a later queue project that may have been relying on at least a portion of
any'osurplus" capacity may then be faced with additional project costs for sub-transmission capacity
additions of their own. As ofthe date of this report, there are no projects in the queue ahead of
I
Point of Change of Ownership
The Point of Change of ownership for the I project will be the spadelocatedontheSeller,ssideofthedisconnectswffiedrawingIabeled2|D.#.
1.3 Custorner'slnterconnectionFacilities
The Seller will install generators, dishibution collector system, stepup transforme(s),
disconnect switches, appropriate grounding measiures, and associated auxiliary equipment.
Seller will build facilities to the Point of Change of Ownership for the generator facility.
for which costs related to sub-transmission capacity upgrades or additionscouIdbepassedontoEshouldchangesbemadetotheirqueuepositionor
generation output. For this and other reasons, the cost estimates included in this FSR are estimates
only, are based on currently known or assumed facts that may not be accurate or materialize, and are
subject to change.
1.1 lnterconnectionPoint
The Point of Interconnection for the Project will be northwest of the
intersection Idaho. A
drawing ts I on page 9
1.2
1.4 Other Faclllties Provided by Seller
1.4.1 Telecommunlcations
In addition to communication circuits that may be needed by the Seller, the Seller
shall provide the following communication circuits for IprC's use:
l. One POTS (Plain Old Telephone Seruice meeting the technical requirements of TR-
NWT-000335:1993; NCI code 02L52-2wfue, loop start,600 ohm) dial-up circuit for
querying the revenue meter and protection relay at the generation interconnect site.
The POTS line must be capable of supporting reliable sustained data communication
at a minimum of 4800 bps with a modem using V.32bis modulation. If that minimum
data rate is or becomes unattainable or unreliable, alternate cincuits will be required -
contact IPC for guidance.
2. One DDS (Digital Data Service meeting the technical requirements of TR-NWT-
000341:1993:,NCI code 04DU5.19, 04DU5.56, or 04DU5.64) data circuit
(guaranteed minimum data rate of 19,200 bits per second) for SCADA between the
generation interconnection site and Boise Bench Transmission Station (2001 Amity
Street, Boise, ID 83716). Please note that Frame Relay Service is not acceptable.
3. One DDS (Digital Data Service meeting the technical requirements of TR-NWT-
000341:1993; NCI code 04DU5.19, 04DU5.56, or 04DU5.64) data circuit
(guaranteed minimum data rate of 19,200 bits per second) for each required Phasor
Measurement Unit (PMU) between the generation intenconnection site and Boise
Bench Transmission Station (2001 Amity Sheet, Boise, ID 83716). Please note that
Frame Relay Service is not acceptable.
The Seller shall provide the required communioations circuits between the
Intenconnection site and IPC's operations to Idaho Power Company's Boise Bench
2
Substation on Amity Road in Boise, Idaho. The communication cirpuits shall be DC
powered (at the terminus locations and within the telecommunications provider's
network) such that they will continue operation during a potver outage for a minimum
of 4 hours, and meet the specified reliability, bandwidth, and latency requirements.
The Seller may choose to coordinate with a third party communications provider to
provide the communications cirsuits and pay the provider's associated one time setup
and periodic charges, or deliver the circuits using their own infrastnrcture, or a
combination thereof. The communication circuits shall be terminated in an approved
demarcation box (cable pairs shall be labeled accordingly) at a location approved by
IPC. The communication circuits will need to be installed, tested and operational
prior to the Seller being allowed to generate power into IPC's system. Note that
installation by a third party communications provider may take several months and
should be ordered in advance to avoid delaying the project.
The Seller or their third party communications provider may need to install
communications equipment (i.e. batteries, multiplexers, etc) near each terminus of the
required communications oircuits. lf this equipment is required, the Seller shall be
responsible to install this equipment in facilitieVlocations that are not owned or
operated by IPC. Note: Century Link and other third party communications
providers typically have this type of equipment near IPC's operations points.
If high voltage protection is required by the local communioations provider for the
incoming cable, the high voltage protection assembly shall be engineered and
supplied by the Interconnect Customer. Options are available for indoor or outdoor
mounting. The high voltage protection assembly shall be looated in a manner that
pnrvides IPC 24-hour access to the assembly for communications trouble-shooting of
IPC owned equipment.
1.4.2 Ground Fault EquiPment
The Seller will install transformer configurations that will provide a ground source to
the transmission system.
1.4,3 Easemenfs and Permits
Easements and permits are required to construct the IPC facilities. IPC will work
diligently in the acquisition of these items; however these authorizations are out of
IPC control and may delay the project. The Seller, at its sole cost and expense, will
provide to IFC the following information for IPC review and approval:
l. a Phase I environmental study for the real property on which the station easement
will be located, which provides warranties for and identifies IE as the User of
the report;
2. an A.L.T.A suruey for the station and transmission line easement and access
easement originating at a public right of way, to include a written legal
description and map of each easement area;
3. a title commitment and cxtended owner's policy title insurance for the station
easement and aooess easement;
4. a distribution line easement for local service to the IPC station as shown in
Figure l.
3
Upon IPC approval of all documents listed above, IPC will supply to the Seller a
completed IPC easement for the station, transmission and distribution lines and
necessary access from a public right-of-way, for signature by the land owner of
record. Once the signatures have been secured, the Seller will return the signed
easement to IPC for reoording.
IPC will submit for permitting to construct the station including the control building
to Elmorc, County.
1.4.4 Generator Output Limit Control
Seller shall install equipment to rcceive signals from IPC Grid Operations for
Generation Output Limit Control (*GOLC") - see Section 3 Operating Requirements
and Appendix A. IPC's recommended method of communication for GOIf is via
fiber between the lnterconnection Station and the hoject.
1.1.5 Local Seryice
The Seller is responsible to arrange for local seryice to their site, as necessary
Included in the cost for the Interconnection Facilities is a new single phase
distribution line extension for local service to the IPC substation.
1.4.6 Meteorological Data
In order to integrate the solar energy into the IPC system and operate IPC's solar
forecasting tool, the Seller must provide solar irradiation and weather data from the
Facility's physical location to IPC via real time telemetry in a form acceptable to IPC.
The associated cost for obtaining this data is the Seller's responsibility.
The data must be provided at l0 second intervals and consist of:
Global Horizontal lrradiance
Plane of Array
Temperature
Wind Speed and Direction
The installed inshuments must equal or exceed the specifications of the following
instruments:
Temperature and Relative Humidity: R.M Young Relative Humidity and
Temperature Probe Sensors Model 41382
Wind: R.M Young Wind Monitor Model05103
Pyranometer: Apogee Instuments Model SP-230
1.5 ldaho Power Company's lnterconnection Facilities
IPC will install aO.23 mile 69 kV transmission tap between the existing
transmission line and the Seller owned substation.tap assumed
1300 feet long or less. To the Point of Change of Ownership, the
equipment and structurcs inside the IPC station will include, a dead-cnd structurg two air-
break switches, a 69 kV cirouit breaker, associated relaying, control and metering equipment
and a control building. Revenue metering will be accomplished on the fiansmission line side
ofthe 69 kV breaker.
n6ekvto be approximately
4
To meet NERC's MOD-II and I3-WECC-CRT-1, Rl.2 r€quir€ments, tPC will install
equipment to collect and transmit Phasor Measurement Unit (PMU) data to IPC. The
communication cirouits required for this data transmission are desoribed above (section
1.4.1). The data can be made available to the Seller on lequest.
The minimum acceptable PMU mcssage rate is 30 samples per second. The minimum set
of PMU measurement channels ref;orded at the POI is shown below. Additional or
substitute channels may be requircd' on a oor casc basis depending on the interconnection
configuration and facility design details.
r FrcouencYo Frequencv Delta (dF/dt)r A-B:C Phase Voltase Magnitudeo A-B-C Phase Voltage Angleo Positive Sequence Voltaee Magnitude. Positive Sequence Voltaee Angler A-B-C Phase Cunent Magnitudee A-B-C Phase Current Ansleo Positive Seouence Cunent Magnitudeo Positive Sequence Cunent Angle
2. Estimated Milestones
These milestones will begin, and the construction schedule referenced below will only be valid, upon
receipt of funding from Seller or its authorized third party no later than the date set forth below for such
payment. IPC will not commit any resources toward project consffuction that have not been funded by
Seller. Additionally, failue by Seller to make the required payments as set forth in this Study by the
date(s) specified below may result in the loss of milestone dates and construction schedules set forth
below. [n the event that the Seller is unable to meet dates as outlined below, Seller may rcquest an
extension of the Operation Date of up to three (3) years. Seller's request will be evaluated by IPC to
ensure Seller's request does not negatively impact other projects in [PC's Generator Interconnection
Queue. Such extension will be allowed only if IPIC determines, in its sole discretion, that the extension
will not negatively impact other projects in IPC's Generator Interconnection Queue. Estimated
milestones, which will be updated and revised for inclusion in the GIA in light of subsequent
developments and conditions, are as follows:
1 Consult with System Planning to determine acceptability.
5
On or before Se/ler
December 15, 2015
February 4,2016 ldaho Power
February '11,2016 ldaho Power
February 18, 2016 Design Confiactor
March 1,2016 Design Contractor
ldaho Power
Design Contractor
March 15,2016
May 31 ,2016
June 15, 2016 ldaho Power
June 30, 2016 ldaho Power and
Design Contmctor
July 15, 2016 ldaho Power
August 1,2016 Construction
Contractor
November 1, 2016 Construction
Contractor
November 15, 2016 ldaho Power
November 15,2016 ldaho Power
D Seller
ldaho PowerD
Executes Generation lnterconnection
Agreement and ldaho Power receives 1)
construction deposit of $1,832,100 or
arangements acceptable to ldaho Power arc
made with ldaho Powefs Credit Department
and 2) acceptable information forthe station
location, geotechn ical and topographical
suruey.
Completes scoping forthe ldaho Power
subsfafron, transmissio n and distribution I ines
(facilities')
Reguesfs design cost quote from selected
design firm, prepares desgn contract
Design @ntruct is fully executed - Design
Contractor Begrns design of the ldaho Power
facilities
Provides documents for Elmore County
pemitting rcquirements
SuDmrts to Elmore County for Conditional Use
Permit (CUP) to construct the facilities
Completes design activities with three
required progress submittals for each design
activity (station structural, control, protection,
scada, communications, transmlbsion and
distibution lines). Two week allowance for
ldaho Power review at each submittal.
Receryes Elmore County permits (90 day
esti m ated permit process d u ration), prcp ares
construction contract docu me nts
Final construction documents are reviewed,
all revisions complete, and final design
document are acceptable to ldaho Power
Execufes consffiiction contract with a
prefened "sole source' contractor
Sfarfs construction of ldaho Powerfacilities
Completes construction of ldaho Power
facilities
ldaho Power Commissioning Complete
Notifrcation fiom ldaho Power's Energy
Contracting Coordin ator confi rmi ng Firsf
Energy of Non-Firm Output
Seller festrhg begins
Notification frcm ldaho Powefs Energy
Contracting Coordin ator confirmi ng Ope ration
6
TB
TB
Date (pending allrequirements arc met) of
Finn Netwo* Resource Output
IPC does not warant or guarantee the foregoing estimated milestone dates, which are estimates only.
These milestone dates assume, among other things, that materials can be timely procured, labor
resources are available, and that outages to the existing transmission system are available to be
scheduled. Additionally, thete are several matters, such as permitting issues and the performance of
subcontraotors that are outside the control of IPC that could delay the estimated Operation Date.
For purposes of example only, federal, state, or local permitting, land division approval, identification of
Interconnection Facilities location, acoess to proposed Interconnection Facilities location for survey and
geotechnical investigation, coordination of design and constuction with the Seller, failure of IPC's
vendors to timely perform services or deliver goods, and delays in payment from Seller, may result in
delays of any estimated milestone and the Operation Date of the project. To the extent any of the
foregoing are outside of the reasonable control of IPC, they shall be deemed Force Majeure events.
The Milestone Schedule above is an expedited schedule whereby Seller has requirtd Idaho Power to
sole source and utilize third party contractor nesources, to expend additional funds, and to take additional
actions in an attempt to meet the Seller's desired completion date before the end of 2016. This
estimated Milestone Schedule depends upon the performance of third party contraotor resources to
expedite their activities, while maintaining proper and adequate managemen! review, and approval from
Idaho Power. Idatro Power will contract with the third party resources, with Seller being an intended
third party beneficiary of said conhact and work. The above estimated Milestone Schedule assumes
that, and depends upon, Seller and the third party contractor/resoutrces doing what is necessary to meet
the required timelines for Idaho Power to complete the work identified in this Agreement.
3. Operating Requirements
IPC shall also provide requirements that must be met by the Seller prior to initiating parallel
operation with the IPC System.
The project is required to comply with the applicable Voltage and Current Distortion Limits found in
IEEE Standard 519-1992IEEE Recommended Practices andrequirementslor hqrmonic Control in
Electrical Power Slstems or any subsequent standards as they may be updated from time to time.
-
will be subject to reductions dirpcted by IPC Grid Operations during
transmission system contingencies and other reliability events. When these conditions occur, the
Project will be subject to Generator Output Limit Control ("GOLC") and will have equipment
capable of receiving an analog setpoint via DNP 3.0 from IPC for GOLC. Generator Output Limit
Control will be accomplished with a setpoint and discrpte output control from IPC to the Project
indicating maximum output allowed. For more detail see Appendix A.
Low Voltage Ride Through: The Project must be capable of riding through faults on adjacent
section of the power system without tripping due to low voltage. It has been determined, through
study, that the Project must be capable of rpmaining interconnected for single line to ground faults:
0.5pu for 26 cycles and 0.31pu for 35 cycles for three phase to ground faults.
7
Seller will be able to modify power plant facilities on the Seller side of the Interconnection Point
with no impact upon the operation of the transmission or distribution system whenever the
generation facilities arc electrically isolated from the system via the 0618 air break switch and a
terminal clearance is issued by IPC's Grid Operator.
F'requency Response Requirements: Generator must be capable of providing Fast Frequency
Response for both positive and negative frequency deviations from 60Hz ( +/- 0.036 Hz) for bulk
electric system disturbances. Minimum respons€ required will be 3o/o (5o/o droop setting provides
3.3o/o of generator's full capacity for a 0.1 Hz deviation) of generator's full capacity for as long as
the generator is able to provide support or the frequency deviation is reduced to within stated limits,
whichever occunl first. Response will only be required when aggregate variable generation on IPC
system is above 35% of load.
4. Reactive Power
The installed reactive power capability of the project must have an, IPC requird power factor
operating range of 0.95 leading to 0.95 lagging at the point of interconnection (POt) over the range
of requested real power output of the project (up to maximum output of 20 MW). The project will
also be requircd to meet the voltage/VAr schedule provided by Idaho Power.
The updated Power flow analysis performed in the System Impact Study indicates that the reactive
compensation range of the proposed hoject at full output has suffioient
capacity to provide a 0.95 leading or lagging power factor at POLTheEProjectwillberequiredtocontroltheVArfloworvoltageatthe69kV
POI per a voltage/VAr schedule provided by ldaho Power Grid Operations. The-
f Project is required to install a plant controller for managing the real and apparent power output
of 20MW(22MVA at the project POI.
Estimated Costs
The following good faith estimates att provided in 2015 dollars and are based on a number of
assumptions and conditions. IPC does not warant or guarantee the estimated costs in the table
below, which are estimates only and are subject to change. Seller will be rcsponsible for all actual
costs incurred in connection with the work to be performed by IPC and its agents, under the terms
and subjeot to the conditions included in any GIA executed by tPC and Seller.
Estimated Cost:
I nkrconnecllon Facililics :
0.23 mile 69 kV transmission line extension, station prop€rty
improvements, fencing dead-end structure, one 69 kV circuit breaker,
two air-break switches, a control building with associated relaying,
control, communication and revenue metering equipment. Also
includes a 3400 ft single phase distribution line extension for station
local service
Upgrades lo Transmiss ion:
Idaho Power
nOTAL
E 1.7s0.000
$1,750,000
I
Two 69 kV transmission air break switchcs (one switch on each side of
the tap).Idaho Power
TOTAL
$82.100
$82,100
GRANDTOTAL $1it32r100
Note Regarding Transmission Seruice:
This FSR is a Netruork Resource Interconnection Facility Study. This FSR identifies the facilities
neoessary to integrate the Generating Facility into IPC's network to sere load within IFC's balancing
area. Netrvork Rosource Interconnection Service in and of itself does not convey any right to deliver
electricity to any specific customer or Point of Delivery.
Note Regarding GIA:
This Facility Study Report (FSR) is a study and preliminary evaluation only and does not constitute, or
form the basis of, a definitive agreement related to the matters described in this FSR. Unless and until a
GLA is executed by IPC and Seller, no party will have any lcgal rights or obligations, exprcss or implied,
related to the subject matt€r of this FSR.
9
Figure 1. Location of Interconnection Facilities
Figure 2. Details of Transmission Line and Station
l0
A.t
4.2
Appendix A
Generation lnterconnection Gontrol Requirements
Generator Output Limit Gontrol (GOLC)
A.1.1 IPC requires Interconnected Power hoducers to accept GOLC sigrrals from our EMS.
A.1.2 The GOLC signals will consist of four points shared between the IPC EMS (via the IPC RTU)
and the Seller's Generator Controller. The IPC RTU will be the master and the Sellet's Generation
Controller will be the slave.
A.1.2.1 GOLC Setpoint An analog output that contains the MW value the Customer should curtail
to, should a GOLC request be made via the GOLC On/Offdiscrete output Control point.
A.1.2.1.1 An Analog Input feedback point must be updated (to reflect the COLC setpoint value)
by the Seller Controller upon the Controllefs receipt of the GOLC setpoint change, with no
intentional delay.
A.1.2.2 GOLC Or/Off: A discrete output (DO) control point with pulsing Trip/Close controls.
Following a "GOLC Om" control (DNP Control Code "Close/Pulse On"), the Customer Controller
will run power output back to the MW value specified in the GOLC Setpoint. Following a "GOLC
Off' control (DNP Control Code "Tri/Pulse On"), the Seller is free to run to maximum possible
output.
A.1.2.2.1 A Discrete Input (DI) feedback point must be updated (to reflect the last GOLC DO
Control Code received) by the Seller Controller upon the Controller's receipt of the GOLC DO
contncl, with no intentional delay. The feedback DI should latch to an OFF state following the
receipt of a "GOLC OFF" contol and it should latch to an ON state following the receipt of an
'GOLC ON" control.
A.1.3 If a GOLC contrcl is issue4 it is expected to see MW reductions start within I minute and plant
output to be below the GOLC Setpoint value within l0 minutes.
Voltage Control
A.2.1 IPC requires Transmission-lnterconnected Power Producers to accept Voltage Contol signals
from our EMS when they are connected to our transmission system.
A.2.2 The voltage control will consist of one setpoint and one feedback point shared between the IPC
EMS and the Seller Controller.
A,2,3 The setpoint will contain the desired target voltage for the plant to operate at. This setpoint will
have a valid control range of 0.95 and the I .05 per unit of nominal system voltage.
A.2.4 The conhol will always be active, there is no digital supervisory point like the Curtail On/Off
control above.
A.2.4.1 When a setpoint change is issued an Analog Input feedback point must be updated (to
reflect the Voltage Control setpoint value) by the Seller Controller upon the Controller's receipt of the
Voltage Control setpoint change, with no intentional delay.
A.2.4.2 When a setpoint change is received by the Seller Controller, the Voltage Control system
should react with no intentional delay.
ll
4.2.4.3 The volt4ge control system should operate at the voltage indicated by the setpoint with an
aocuracy of +l- 0.5o/o of the nominal system voltage.
A.2.5 The Seller should supervise this control by setting up "rtasonability limits", i.e. configure a
reasonable range of values for this control to be valid. As an example, they will accept anything in the
valid confrol range (between .95 and 1.05 p.u.), but reject values outside this range, If they were fed an
eroneous value outside the valid range, their control system would default to the last known, good value.
4,3 Generation lnterconnection Data Points Requirements
Digital Inputs to Idaho Power (DNP Obj. 01, Var.2)
Index Description state (0/l)Comments:
0 52A Customer Capacitor Breaker (if present)Open/Closed Sourced at station
I GOLC Otr/On (Control Feedback)Off/On Feedback provided by Seller
Digttal Outputs to Customer (DNP Obj. 12, Yer. 1)
Index Doscription Comments:
0 GOLC Off/On Control issued by ldatro Power
Analog Inputs to IPCo (DNP Obj. 30, Var. 2)
Index Description
Raw
Hish
Raw
Low
EU
Hieh
EU
low
EU
Units Comments:
0
GOLC Setpoint Value Received
(Feedback)32767 32768 TBD TBD MW
Provided by
Seller
I
Voltage Contol Setpoint Value Rec'd
(Ieedback)32767 32768 TBD TBD KV
Provided by
Seller
Analog Outputs to Customer (DNP Obj.41, Var.2)
Index Description RawHish
Raw
Low
EU
Hish
EU
Low
EU
Units Comments:
0 GOLC Setpoint 32?67 -32768 TBD TBD MW
Control issued by Idaho
Power
I Voltaee Conhol Setpoint 32767 -32768 TBD TBD KV
Control issued by Idaho
Power
t2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-20-30
IDAHO POWER COMPANY
ATTACHMENT 3 TO REQUEST NO.2A
TO
IDAHO POWER COMPANY'S RESPONSES TO
STAFF'S SECOND PRODUCTION REQUEST
GENERATOR INTERCOI\IhIECTION
SYSTEM IMPACT STUDY REPORT
for integration ofthe proposed
3MW
rPc PROJECT QUEITE #532
to the
IDAHO POWER COMPANY ELECTRICAL SYSTEM
for
I.
REPORT v.0
Manch,2019
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(CEID. Distribution ofthis report must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power company and have a need to know.
Date Revision Initials Summary of Changes
3ll2r20r9 0 AV SISR GI #532 - Original issue.
Revision History
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Table of Contents
1.0 Introduction ......................... I
2.0 Summary... ..........................1
3.0 Scope of lnterconnection Transmission System Impact Study.......... ...............2
4.0 Description of Proposed Generating Project........ .........................3
5.0 flescription of Transmission Facilities............... ....... 3
6.0 Description of Power Flow Case ............4
7.0 Power Flow Analysis Study Results..,.... ....................4
8.0 Description of Substation Facilities. ......................... 4
9.0 Description of Distribution Faci1ities.................. .......5
10.0 Short Cirouit Study Resu1ts................ ......................... 5
I1.0 Description of Required Facility Upgrades ................ s
l2.O Description of Operating Requirernents................ .......................7
13.0 Conclusion ........ g
APPENDIX A................ ..................9
A-1.0 Method of Study ..........9
A-2.0 Aocepability Criteria .......................9
A-3.0 GroundingGuidance.... ................... l0
A4.0 Electrioal System Protection Guidance ............ l0
A-5.0 WECC Coordinated Off-Nominal f,'requency Load Shedding and RestorationRequirements.............. ............ l0
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B-1.0 GI Project #532 Site Location..... ......... I I
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List of Tables
Table I Conceptual-level Cost Estimate for GI #532 6
List of Figures
3 MW Vcrde Light Powcr Project
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1.0 Introduction
Inc. has contracted with tdaho Power Company (IPC) to perform a
Generator Interconnection System Impact Study for the integration of the proposed 3 MW I
(the Project). The Project is proposed to be located in IPC's Western Region
in Malheur County, Oregon (See Figure 2:Locationofl
I-GI#532in Appendix A). The project latitude and longitude are approximately
The Project is Generation Interconnect queue number 532 (GI #s32).
The project has applied to connect to the Idaho Power distribution systom for an injeotion of 3
MW at a single Pbint of Interconnection @OI) at 12.47 kilovolts (kV). The POI evaluated is
located in ttre Ontario (ONTO) 019 distribution circuit boundary approximately I
This report documents the basis for and the results of this System Impact Study for the GI #532
Generation Interconnertion Customer. The report describes the proposed project, the
determination of project interoonnection impact and estimated costs for integration of the Project
to the Idaho Powir System. This report satisfies the System Impact Study requirements of the
Idaho Power Tariff.
2.0 Summary
The system impact of interconnecting the 3 MW IPC's 12.47 kV
ONTO-019 distribution feeder was evaluated. The POI is located at
The transmission system and distribution analysis indicated that interconnecting thel
ONfO-Otq will have minimal system impact with modifications discussed in
this report.
The Pncject will be required to control voltage in accordance with a voltage schedule as provided
by tdatro Power Grid Operations. Therefore, GI #532 will be requircd to install a plant controller
for managing the real and reactive power output of the 3 MW inverter array at the project POI.
Generator interconnection service, either as an Energy Resouue or a Network Resource, does
not in any way convey any right to deliver electricity to any specific customer or point of
delivery.
ThetotalpreliminarycostestimatetointerconnecttheEtheoNTo-
0l 9 distribution feeder is $327,45 l, and includes the following tasks:
o Install a four-pole 12.47 kY generation interconnection package at the POI. Thjs includes
an SEL-421 protective relay, which requires 3-phase potential transformers (PTs), 3-
phase current transformers (CTs), SCADA and remote connectivity.
I Install a single-phase PT and wiring for dead-line check on oNTo-OI9.
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. Install Beckwith M2001-D load tap changer (LTC) controllers on the Tl35 transformer at
ONTO substation.o Upgrade the ONTO T023 AMI transformer.r Move recloser ONTOI9RIO5 approximately 0.5 miles.o Add aX-blade switphto ONTOI9o Add two sets of 3 phase fused and one set of I phase fuses to distribution circuit laterals.
The cost estimate includes direct equipment and installation labor oosts, indirect labor costs and
general overteads, and a contingency allowance. These arc cost estimates only and final charges
to the customer will be based on the actual construotion costs incurred. It should be noted that the
preliminary cost estimate of $327,451 does not include the cost of the customer's owned
equipment to construct the solar generation site or required communication circuits.
3.0 Scope of Interconnection Transmission System Impact Study
The Interconnection Transmission System Impact Study was completed, in accordance with
Idaho Power Company Standard Generator lnterconnec'tion Procedures, to provide an evaluation
of the systern impacts ofthe interponnection of the proposed generating project to the Idaho
Power system. As listed in the Interconnection Transmission System Impact Study agreemen!
the Interconneotion Transmission System Impact Study report provides the following
information:
r identification of additional transformer load tap changer opemtions, voltage fluctuations
(flicker) and additional feeder losses.o identification of required reactive power support.o identification of islanding conditions.o identification of any circuit breaker short cirpuit capability limits exceeded as a result of
the interconnection.o identification of any thermal overload or voltage limit violations resulting from the
interconnection.r identification of any angular instability.o description and non-binding estimated cost of facilities required to interconnect the Small
Generating Facility to the IPC System and to address the identified short circuit and
powcr flow issues.
All other proposed generation projects prior to this project in the Generator Interconnect queue
wene considered in this study. A current list of these projects can be found in the Generation
Interconnection folder located on the Idaho Power web site at the link shown below:
htto :/Amvw.oatioasis.comfi oco/index.btml.
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4.0 Description of Proposed Generating Project
Gl#532, consists of a single 3 MW photovoltaic solar plant which requested
to be connected to tdaho Power's 12.47 kV ONTO-019 distribution feeder. The Project will need
to install a plant controller for managing the real and reactive power output. The supplied single
line drawing shows the project using
finverters. The drawing shows
frn ith fused disconnects.
5.0 Description of Transmission Facilities
The Project's impact on the Brownlee East transmission path (WECC Path #55) was evaluated in this
Transmission System Impact Study. In addition, the ldaho-Northwest fransmission path (WECC Path
#14) which is in series with the Brownlee East fiansmission path was studied at its rated West'to-
East tansfer capaclty.
The ldaho-Northwest transmission path (WECC Path #14) is defined as the sum ofthe flows on the
following five lines:o Oxbow-Lolo 230kV. Hells Canyon-Hunicane 230kVr North Powder-La Grande 230kVo Hines-Hamey ll5kVr Hemingway-Summer Lake 500kV
The Brownlee East transmission path (WECC Path #55) is defined as the sum of the flows on the
following seven lines:. Brownlee-Boise Bench #l 230kVo Brownlee-Bohe Bench #2230kVo Brownlee-Boise Bench #3 230kVo Brownlee-Horse Flat #4 230kVc Brcwnlee-Ontario230kVr Oxbow-Starkey l38kvr Quartz-Ontario l38kV
For this generation intelponnection Transmission System Impact Study, the flow on the Idaho-
Northwest transmission path was modeled at I MW West-to-East and the Brownlee East
transmission path was modeled atI MW West-to-East. The paths were shessed to these speoific
levels in order to determine if the addition of the Project's 3 MW degraded the existing Brownlee
East path's transfer capability.
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6.0 Description of Power Flow Case
This study utilized the WECC apploved lghs3al Heavy Summer operating case as the starting
point ofthe studies. Two power flow cases were developed:
o The "Base Case" with projects earlier in the queue added, but not the Project.o The "Second Case" with projects earlier in the queue and the Projcct added.
The pre-contingency flows across the ldatro-Northwest and the Brownlee East pathVcut-planes
were modeled at their respective ratings (see Section 5.0). Flow in each path is modeled in this
manner in order to capture the potential impact of the Project on the existing capabilities of the
surrounding paths and the interconnected transmission systems. Performing the studies at these
levels will ensurc that the Total Transfer Capability ofthe adjacent paths are not impacted by the
Ptoject.
In addition to the l9hs3a Heavy Summer operating case, a light-load operating case was
developed for the IPC 69 kV sub-transmission system. The limits uscd for this analysis are as
follows:
l. Voltage magnitude during normal operating steady-state must remain between 0.93 per
unit and 1.05 per unit. [f the post-hansient voltage deviates from this range during N-l
conditions and an operating pnrcedue can be taken to return the voltage to the required
range without creating a four-terminal line, then network upgrades ane not required.2. Line loading must be less than l00o/o of line rating during normal steady-state operation.
Steady-state line loading above 100% requires network upgrades.3. Post-transient line overloading that does not exceed the emergency line rating resulting
from an N-l contingency is acceptable if an operating procedure can be taken to reduce
the line loading below 100% without creating a four-terminal line.
Post-transient line loading above the emergency line rating rcsulting from an N-l contingency
nequires network upgrades.
7.0 Power Flow Analysis Study Results
Results from the stressed Heavy summer operating case indicate the addition of the Gl#532
project will not result in contingency violations that would impact the Total Transfer Capability
of the adjacent Path 55 Brownlee East transmission path.
The addition of GI #532 does not exceed any lines ratings for any N-l contingencies.
E.0 Description of Substation Facilities
Idaho Power's ONTO substation is located in Malheur County, Oregon. The existing substation
transformer, ONTO T135, is a three-phase 138-13.09 kV transformer rated for 37 MVA.
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9.0 Description of Distribution Facilities
The requested POI for the Project is on the ONTO-019 distribution feeder. This is a grounded-
wye feeder operating at 12.47 kV at the POt. The Project must have a grounded-wye ilansformer
connection on the IPC side, as well as a wye connection on the Projeot side of the transformer.
Refer to Appendix A, Section 3, for additional grounding requirements.
10.0 Short Circuit Study Results
Fauh hrtv at OI{TO ffttSl 12.5 kV Bus:
SIG Fault (A)I
3PH Fault (A)I
Fauh DuUet FOI -Sohr 12.5 kVBtts:
SLG Fault (A)I
3PH Fault (A)I
The fault oun'ent contribution from the PV generators does not exceed any circuit breaker rating.
11.0 Description of Required Facility Upgradm
The Project will be required to provide a plant confioller that will operate the inverter system in
Volt/VAr control mode in order to regulate voltage according to a voltage schedule that will be
provided by Idaho Power.
The following upgrades will be required to lPC-owned facilities to facilitate the interconnection
ofGI #532:
o Install a four-pole 12.47 kV generation interconnection package at the POI. This includes
an SEL-421 protective relay, which rcquircs 3-phase potential trutsformers (PTs), 3-
phase cunent transformers (CTs), SCADA and remote connectivity.
o Install a single-phase PT and wiring for dead-line cheok on ONTO-019.
o Install Beckwith M2001-D load tap changer (LTC) contollers on the Tl35 hansformer at
ONTO substation.r Upgrade the ONTO T023 AMI transformer.o Move reoloser ONTOI9RI05 approximately 0.5 miles.. Add aX-blade swirchto ONTOI9
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a Add two sets of 3 phase fused and one set of I phase fuses to distribution circuit laterals.
See the conceptual-level cost estimate in Table l.
Table I Conceptual-level Cost Estimate for GI #532
Item of Work Estimate
Generation interconnection and protection package
Substation upgrades
Distribution upgrades
$179,800
$0
$58,000
Unloaded costs
Contingency 20% (l)
$237,800
$47,560
Total unloaded oosts
Overheads (2)
$285,360
$42,091
Total loaded oosts
Total Conceptual-level Cost Estimate in 2019 dollan (3)
$327,451
st27,451
(l) Contingency is added to cover the unforeseen costs in the estimate. These costs cen include unidentified design
componcnts, mdcrial cost increases, labor cstimate shortfalls, etc.
(2) Overhead costs cover the indirect costs associated with the project.
(3) This cost estimate includes direct cquipment, material, labor, overhcads, and oontingcncy as shown.
o Notc that these estimates do not include the cost of the customer's equipment/facilities or
required communication circuits for SCADA, and metering.o Note that the overhead rates are subjoct to ohange during the year.o These are estimated oosts only and final charges to the customer will be based on the
actual construction costs incurred.
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. These arc non-binding conceptual level cost estimates that will be firther refined upon
the request and completion of Transmission and Distribution Facility Studies.
l2.O Description of Operating Requiremen6
The Project shall be capable of injecting r€active power (over-excited) and absorbing reactive
power (under-exoited) equal to 1.32 MVAR at all active power output between 2070 and 1007o
of the nameplate active power rating of 3 MW.
0tl
o,u 001?-
o.ll lca..dlSnl
)Irbora-l
ll.tidlrua.?.rdaal
Figurc I Operating rcquircmentc
The inverter(s) will be required to have the UL l74lSA certification prior to the installation.
The Project will be required to conbol voltage in accordanoe with a voltage schedule as provided
by ldatro Power Grid Operations. Thercfore, GI #532 will be required to install a plant oonfitller
for managing the rral and reactive power output of the 3 MW inverter system at the project POI.
Voltage flicker at startup and during operation will be limited to less than 5% as measured at the
POI. The allowable voltage flicker limit is further rcduced during operation due to multiple
voltage fluctuations per hour or minute, per Idaho Power's T&D Advisory Information Manual.
The Project is required to comply with the applicable voltage fluctuation limits found in IEEE
Standard 1453-2004 IEEE Recommended Practicefor Measurement and Limits of Yoltoge
Fluctuatiotts and Associated Light Flicker on AC Power Systems.
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The project is required to comply with the applicable Voltage and Cument Distortion Limits
found in IEEE Standard 519-2014 IEEE Recommended Proctices ond Requirementsfor
Harmonic Control in Electrical Power Slstems.
Additional operating rcquircments for the Project may be identified in the System Impact Study
when it is performed.
13.0 Conclusion
The requested interconnection of the Gl#532, to ldaho Power's
system was studied for impact to the IFC elecffical transmission and distribution system. The
project will need to interconnect using r12.47 kV grounded-wye connection to the ONTO-0I9
12.47 kV distribution feeder.
The results of this study confirm that, with the modifications listed, no network upgrades willbe
required to interconnect the Gl#532,to the existing tdaho Power
system. A four-pole generation interconnect paokage, deadJine checlq and a digital tap changer
control on the ONTO Tl35 are required to integrate the 3 MW.
All generation projects in the area ahead of the Projeot in the IPC generation interconnection
queue and their associated transmission system improvemcnts were modeled in a preliminary
power flow analysis to evaluate the feasibility of interconnecting Gl#532. The results and
conclusions of this System Impact Study are based on the realization of these projects in the
unique queue/proj ect order.
The estimated cost to interconnect GI #532to the IPC system atthe 12.47 kV point of
interconnection considered in this study is approximately $321,451.
Generator interconneotion service, either as an Energy Resource or a Network Resource, does
not in any way convey any right to deliver electricity to any specific customer or point of
delivery. Transmission requirements to integrate the Project will be determined during the
System Impact Sfirdy phase of the generator interconnection process.
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(CEID. Distribution of this r€port must be limited to parties that have entered into a non-
disclosure agreement with ldaho Power Company and have a need to know.
APPENDU( A
A-1.0 Method of Study
The Transmission System lmpact Study plan inserts the hoject up to the maximum requested
injection into the selected Western Electicity Coordinating Council (WECC) power flow case
and then, using Power World Simulator or GE's Positive Sequence Load Flow (PSLF) analysis
tool, examines the impaots of the new resource on Idaho Power's transmission system (lines,
transformers, etc,) within the study area under various operating and outage scenarios. The
WECC and Idaho Power reliability criteria and ldaho Power operating procedures were uscd to
determine the acceptability ofthe configurations considered. The WECC case is a rccent case
modified to simulate stessed but reasonable pre-contingenoy energy transfers utilizing the IPC
system. For distribution feeder analysis, Idaho Power utilizes DNV'GL's Synergi Elechic
softrnare and EPRI's OpenDSS softwarc.
A-2.0 Acccptebility Criteria
The following acceptability oriteria were used in the power flow analysis to determine under
which system configumtion modifications may be required:
The continuous rating of equipment is assumed to be the normal thermal rating of the
equipment. This rating will be as determined by the manufacturer of the equipment or as
determined by ldaho Power. Less than or equal to 100% of continuous rating is
acceptable.
Idatro Power's Voltage Operating Guidelines were used to determine voltage
requirements on the system. This states, in part, that distribution voltages, under normal
operating conditions, are to be maintained within plus or minus 5% (0.05 per unit) of
nominal at each meter or POI on the feeder. Therefore, voltages greater than or equal to
0.95 pu voltage and less than or equal to 1.05 pu voltage are acceptable.
Voltage flicker during the starting or stopping of the generator will be limited to less than
5% as measured at the POI. Allowable volage flicker limit is furtherreduced during
operation due to multiple voltage fluctuations per hour or minute, per Idatro Power's
T&D Advisory Information Manual.
Idaho Power's Reliability Criteria for System Planning was used to determine proper
tansmission system operation.
All customer generation must meet IEEE 519, IEEEI453, IEEEI547, and ANSI C84.1
Standards.
All other applicable national and ldaho Power standards and prudent utility practices
werc used to determine the acceptability of the configurations considered.
3MW
Feasibility Study Report 9
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This report contains tdaho Power Company Critical Energy Infrastructure Information
(CEID. Distribution of this report must be limited to parties that have entered into a non-
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The stable operation of the system requires an adequate supply of volt-amperes reactive
(VAR$ to maintain a stable voltage profile under both steady-state and dynamic system
conditions. An inadequate supply of VARs will rcsult in voltage decay or even collapse
under the worst conditions.
Equipment/line/path ratings used will be those that are in use at the time ofthe study or that are
represented by IPC upgrade projects that are either ountntly under construction or whose
budgets have been approved for oonstuotion in the near futune. All other potential future ratings
are outside the scope of this study. Future fransmission changes may, however, affect current
facility ratings used in the study.
A-3.0 GroundingGuidance
IPC requires interconnected transformers on the distribution system to limit treir ground fault
curent to 20 amps at the Point of Interconnection.
A-{.0 Electrical System Protection Guidance
IPC requires electrical system prctection per Rcquirements for Cencration Interconnections
found on the ldaho Power Web site,
http:/ftvww.idahonowcr.com/odfs/BucinessToBurinc$dfecilityRoouircmentg.pdf
A-5.0 WECC Coordinated Olf-Nominal X'requency Load Shedding and Restoration
Requirements
IPC requires frequency operational limits to adhero to WECC Under-frequency and Over-
frc.quency Limits per the WECC Coordinated Off-Nominal Frequenoy Lnad Sheddins and
Restoration Requirements available upon request.
3MW
System Impact Study Report l0
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This report contains ldaho Power Company Critical Energy Infrastructure Information
(CEII). Distribution of this rcport must be limited to parties that have entered into a non-
disclosure sgreement with Idaho Power Company and have a need to know.
B-1.0
APPENDD( B
GI Project #532 Site Location
3MW
System Impact Study Report l1
OFFICIAL USE ONLY
This report contains ldaho Power Company Critical Energy Infrastructure Information
(CEID. Distribution of this report must be limited to parties that have entered into a non-
disclosure agreement with Idaho Power Company and have a need to know.