20200720Ellsworth Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSTON
IN THE MATTER OE IDAHO POWER
COMPANY' S APPLICATTON FOR
AUTHOR]TY TO ESTABLISH TAR]FE
SCHEDULE 68, INTERCONNECTIONS TO
CUSTOMER DISTRIBUTED ENERGY
RESOURCES
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CASE NO. IPC.E.2O-30
rDAHO POWER COMPANY
DIRECT TESTIMONY
OE
Jared L. Ellsworth
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O. Pl-ease state your name, business address, and
present position with Idaho Power Company ("Idaho Power" or
t'Company" ) .
A. My name is Jared L. Ellsworth. My business
address is 7221 Wesl Idaho Street, Boise, Idaho 83702. I
am employed by Idaho Power as the Transmission,
Distribution & Resource Planning Director for the Planning,
Engineering c Construction Department.
O. Please describe your educational background.
A. I graduated in 2004 and 2010 from the
University of Idaho in Moscow, Idaho, receiving a Bachefor
of Science Degree and Master of Engineering Degree in
Electrical Engineering, respectively. I am a Iicensed
professional engineer in the State of Idaho.
A. Pl-ease describe your work experience with
Idaho Power.
A. In 2004, I was hired as a Distribution
Planning engineer in the Company's Delivery Planning
department. My principal responsibilities included
developing distribution circuit, substation, and sub-
transmission projects to meet growth needs primarily
related to equj-pment capacity and vol-tage delivered to the
customer meter. In 2001, I moved into the System Plannlng
department, where my principal responsibilities included
planning for bulk high-voltage transmi.ssion and substation
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Idaho Power Company
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t projects, generation interconnection projects, and NERC
2 reliability compllance standards. f transitioned into the
3 Transmission Policy & Devel-opment group with a similar
4 rol-e, and in 2013, I spent a year cross-training with the
5 Company's Load Serving Operations group. In 2A14, I was
6 promoted to Engineering Leader of the Transmission Policy &
7 Development department and assumed leadership of the System
8 Planning group in 2018. In early 2020, I was promoted into
9 my current role as the Transmission, Distribution and
10 Resource Planning Director. I am currently responsible for
11 the planning of the Company's wires and resources to
L2 continue to provide customers with cost-effective and
13 reliable electrical service.
14 O. How is your testimony organized?
15 A. I wiII provide a general overview of the
16 Company's electrical system and how customers with
L7 Distributed Energy Resources ("DER" or "DERs") utilize the
l-8 Company's distribution system. I will then describe the
19 Company's request to implement the functionality of smart
20 i-nverters in accordance with Commission Order No. 34046
2L issued in Case No. IPC-E-17-13. Next, I will explain the
22 Company's proposed interconnection requirements for
23 customers seeking to interconnect a non-exporting system Lo
24 meet a portion of their electricity needs while
25 simul-taneously maintaj-ning an electrical connection to the
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Idaho Power Company
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grid ("in Parallel"). Fina1ly, I wilI provide an overview
of the rationale for the Company's proposed process as it
rel-ates to interconnecting energy storage devices.
I. IDAIIO PO|ER'S GRID
O. What is meant by the term "the grid"?
A. The grid, in this context, is the electric
power system, including the generation, transformation,
transmission, distribution, and delivery of energy in the
form of electricity to customers.
Fiqrure 1: The Grid
Generation converts energy contained in reservoirs,
fossil fuels, wind, geothermal wel-Isr or solar rays to
electricity. Generation stations are often located remote
from customers' point of use; therefore, the el-ectricity is
transformed to extremely high voltages to reduce electrical
Iosses and moved on transmission l-j,nes over long distances.
Once the electricity is delivered to communities, it is
transformed to a lower voltage at substations and
distributed through the local community on distribution
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Idaho Power Company
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l-ines. A final stage of transformation is used to reduce
voltage to deliver electricity to customer's homes.
O. Which services does the grid offer Idaho
Power's customers?
A. The grid offers reliable and dependable
electricity delivery across large regions in nearly the
instantaneous time of a customer's demand. The grid also
provides flexibility by allowing the utility access to a
diverse portfolio of resources for power generation, even
if those resources are l-ocated vast distances from where
the power is needed.
O. What functions does Idaho Power perform in
order to maintain a safe and reliable distribution system
and grid?
A. In order to provide safe and reliable energy
on demand, Idaho Power must perform the following
functions: voltage control, system protection, scheduling,
dispatching, and l-oad balancing. These functions are
commonly referred to, and coll-ectively known as ancillary
services.
o How does fdaho Power control voltage to
safe and reliable distribution system and grid?
Voltage control is achieved by managing the
22 maintain a
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voltage
system,
throughout the grid at the generator, transmissj-on
and distribution system. The voltage regulating
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Idaho Power Company
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1 devices control- the voltage output of the generators to
2 match the voltage requirements established by personnel
3 within the Company's dispatch controL center ("System
4 Operator"). At the substations, System Operators also
5 remotely switch substation capacitors and inductors to
6 raj-se and lower the transmission voltage, respectively.
7 Automatj-c voltage management occurs at the distribution
B substation transformers with voltage control- based on load,
9 known as load tap changers. For longer distribution
10 circuits, distributlon regulators can be added away from
11 the substation for additional voltage control. Additional
1,2 automatic control signals are sent to switched distribution
13 cj-rcuit capacitors based on substation transformer Ioading.
L4 FinaIly, voltage control occurs at substations that service
15 large commercial and industrial customers.
16 0. Does the distribution system provide other
L1 services that are specific to a customer with a DER?
18 A. Yes. The grid provides several services for
19 customers with DERs, but most specific to the scope of this
20 case, the distribution system enables inverter operation.
21 0. What is an inverter?
22 A. An inverter is a power electronics device that
23 converts direct current (*DC") electricity into alternating
24 current ("AC") electricity. Inverters are used in both
25 off-grid and on-grid applications.
ELLSWORTH, DI
Idaho Power Company
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l- Q. What types of DERs reguire an inverter?
2 A, Any DER that produces DC energy requires an
3 inverter. An inverter j-s required for customers who
4 install a solar photovoltaic (*PV") generation system or an
5 energy storage device because solar panels and batteries
6 produce DC electricity, but home appliances require AC
7 power.
I Q. How does Idaho Power define a Distributed
9 Energy Resource?
10 A. In Schedule 68, Interconnections to CusLomer
11 Distributed Energy Resources ("Schedul-e 68"), lncluded as
L2 Attachment No. 1 to the Application, the Company proposes
13 to define a DER as a source of electric power that is not
L4 directly connected to the bulk power system. For purposes
15 of administerlng the proposed Schedule 68, a DER is any
15 combination of a qeneration facility or an energy storaqe
L7 device connected in Paralle1 to Idaho Power's system.
18 0. How does the grid enable inverter operation?
1,9 A. The majority of inverter-based systems
20 connected to Idaho Power's grid are considered "on-grid"
21, systems. For on-grid systems, the DC electricity generated
22 by the sofar PV system is sent directly to an on-grid
23 inverter, whlch converLs the electricity to AC for use by
24 the customer or sent to the grid. Without t.he grid, the
25 customer's generation system wouLd not operate because
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these on-grid inverters require an AC voltage grid
connectioni without this connection, the inverter would not
be able to develop voltage or deliver energy. In other
words, the grid must be present for customers with on-grid
inverters to operate their systems. For the purposes of my
testimony, the discussion regarding inverters will be
specific to on-grid inverters.
rI. IMPACTS OF DER ON IDAHO POWER'S DISTRIBTXTION SYSEEM
O. Please describe a typical distribution
circui-t.
A. HistoricaIIy, the distribution system coul-d be
characterized as a downhill flow of power from electrical
substations, across distribution circuits, to customers.
Absent DERs, power comes from centralized generators
through the transmission system, and the distribution
substation regulates the voltage of distribution circuits
to deliver energy to customers. As energy travels across
the distribution circuit further from the distribution
19 substation, it is delivered at reducing amounts of voltage.
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American National Standards
C84. L Range A specifies that
must be ln the range of plus
nominal vo1t.age, i.€. , 0. 95
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Institute (*ANSf")
voltage provided to customers
How do DERs affect distribution system
or minus five percent of the
- 1.05 per unit ("pu").
ELLSWORTH, DI
Idaho Power Company
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25 operations?
1 A. DERs add a two-way power flow dynamic to the
2 distribution system, so the historical downhill, flow of
3 power may no longer apply. In most installations, this
4 dynamic is inconsequential; however, there are cases where
5 DERs can negatively impact the performance of a
6 distribution circult. Two such cases are (1) voltage rise
7 eausing high voltage and (2) voltage deviations.
I Q. Please describe what you mean by the term
9 "voltage rise" that may be caused by DER systems.
10 A. Voltage rise occurs when customer generation
lL exceeds customer demand, and power flows back toward the
L2 substation transformer.
13 ANSI standard C84.1 Range A specifies that service
74 voltage be delivered to customers within a voltage range of
15 0.95 to 1.05 of nominal voltage. A typical voltage profile
16 for a dlstribution circuit begins with a maximum voltage,
I7 approximately 1-.03 pu, at the distribution substat j-on
18 transformer, and voltage will reduce with the distance from
19 the substation. For distribution clrcuits with high
20 penetrations of customer-ohrned DERs, the 0.02 pu difference
2L between the 1.03 at the distribution substation, and the
22 1.05 ANSI Range A maximum voltage, can provide challenges
23 in integration.
24 O. Does the Company typically investigate
25 voltage rise for customer generation applications?
ELLSWORTH, DI B
Idaho Power Company
1 A. Yes. The Company has studj-ed this issue
2 frequently with the PubIic Utility Regulatory Policies Act
3 ("PURPA") projects connecting to the distribution system.
4 The Company also monj-tors other utility jurisdictions with
5 higher penetrations of DERs and voltage rise. Voltage
6 rise, in particular, is one of the issues that can be
7 addressed through smart inverters.
8 Q. What are tlpical means to address voltage
9 rise?
10 A. Voltage rise is a function of the conductor
11 size between the generation and the substation. One
12 solution to reduce the voltage rise is to upgrade the
l-3 conductor with a larger slze. This solution is generally an
L4 expensive option.
l-5 Another sol-ution is to change the settings on the
16 voltage regulator to hol-d the voltage lower and al-low for
t1 reverse power flow. This solution is dependent on the
1B distributlon configuration and wiII not work in al-I
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20 The third option is to use smart inverter settings
2l for reactive power control functions. This is the most
22 economical solution.
23 o Please descri-be what you mean by "voltage
solar PV.
ELLSWORTH, DI
Idaho Power Company
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24 deviations" that may be caused by
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A. Distribution circuits have devices such as
load tap changers, regulators, and shunt capacJ-tors, that
are installed to manage the voltage at various points on
the distribution circuit. These devices respond to voltage
changes over a few seconds. The output from a solar PV
system changes more rapidly than can be managed by the
distribution devices, impacting other customers in the near
proximity.
0. It'7hy would a reduction of voltage deviation, a
power quality issue, be the responsibiJ-ity of the customer
with a DER?
A. In most cases, it is the customer wj-th a DER
that creates the voltage deviation, especially in locations
with high levels of penetration. Section 4 of Idaho
Power's RuIe K governing Customer's Load and Operations
states "[t]he Customer is solely responsible for the
selection, installation, and maintenance of all electrical
equipment and wiring (other than the Company's meters and
apparatus) on the load side of the Point of Delivery." It
is also the customer with a DER that can cost-effectively
mitigate the deviation through the installation of a smart
inverter. The alternative would be more costly
distribution system upgrades required to alfow continued or
expanded operati-on of the customer-generators.
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Idaho Power Company
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III. REQUESI !O IIIPI.EIIBTE SIIART INVERTER TUNCTIOITALITY
O. What is a smart inverter?
A. A smart inverter 1s an inverter that provides
configurable functions beyond the conversion of DC to AC.
A few of the features are voltage/reactive power control,
anti-isl-anding, monj,toring, and remote communication.
0. Does the Company currently require that
customers who install an inverter-based DER interconnect to
the grid using a smart inverter (s) ?
A. No. Section 2 of the current Schedule 72,
Interconnections to Non-Utility Generation ("ScheduLe 72")
found in Attachment Nos. 2 and 3 to the Application,
requires that on-grid inverters have either a certification
with Underwriters Laboratories Standard for Inverters,
Converters, Control-fers and Interconnection System
Equipment for Use with Distributed Energy Resources UL ),7 4L
('UL Ll47"1, Institute of Electrical and El-ectronj-c
Engineers fnterconnecting Distributed Resources with
El-ectric Power Systerns Standard L547 (*IEEE 1541" ) or be
subject to thj-rd-party testing performed at the customer's
expense.
O. What is the Company recommendi-ng in this
filing regarding smart inverters?
A. The Company is requesting authorization to
adopt the revised IEEE standards in compliance with Order
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No. 34047 i-ssued in Case No.
seeks to include the language
Schedule 68, to require that
smart inverter that meets the
revised IEEE standards.
IPC-E-17-l-3. This f iling
in the newly proposed
customers with DERs install a
requirements defined in the
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a What is the purpose of the IEEE 1547 and
1541.1 Standards?
A. The IEEE DER interconnection standards (IEEE
1547 and IEEE 1547.1) comprise the industry's benchmark and
definitively establish the functional requirements for the
proper interconnection of DERs withln an Area Electric
Power System (the utility). IEEE L547 specifies the
functionaL requirements for interconnection, including
desi-gn, production, and lnstallation commissioning
evaluation. IEEE l-547.1 specifies the equipment
conformance test and evaLuation procedures.
0. What is the purpose of the adjustable smart
inverter variables?
A. The smart inverter variables are adjusted to
set the normal operating performance categories (Category A
or B) and abnormal- voltage and ride-through operating
performance categories (Category I, II, or III).
0. What smart inverter functionality does the
Company propose requiring to maintain normal operating
voltage within the acceptable range?
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Idaho Power Company
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1 A. The Company proposes voltage operational
2 guidelines for inverter-based DERs to be set for normal
3 operating performance Category B. The reactive power
4 control setting will be a voltage-reactive function with a
5 voftage dead band between 0.98 and 1.03 pu. When the
6 voltage falls below the dead band, 0.98 pu, the vol-t-ampere
7 reactive ("var") requirements will go from 0 to a maximum
8 var requirement of 44 percent of nameplate kilo-voLt-ampere
9 (\rkVA") injecting at 0.92 pu. When the voltage rises above
10 the dead band, 1.03 pu, the var requirement wiII go from 0
11 to a maximum of 44 percent of nameplate kVA absorbing at
L2 1.06 pu.
13 O. V[hy did the company select the 0.98 to 1.03
74 pu dead band?
15 A. The Company selected the 0.98 to 1.03 pu
16 dead band to maximize the amount of time inverter-based
17 DERs spend within the dead band, in other words, operating
18 at unity power factor, while still allowing for voltage
79 support during times of need.
20 O. Why is the Company recommending minimum
2L (0.92 pu) and maxj-mum (1.06 pu) voltage settings outside of
22 the ANSI C84.1 Range A 0.95 to 1.05 pu service voltage?
23 A. The 0.92 and 1.06 pu voltages represent
24 approximations to ANSI standard C84.1 Range B. Range B
25 specifies a wider allowable service voltage range to
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customers; however, service voltages outside the 0.95 to
1.05 Range A limits should be infrequent, per the standard.
These lower and higher limits in the smart inverters al1ow
for var support over a wider range of voltages and ensure
the need to supply maximum var support, injecting or
absorbing, wil-l be infrequent.
O. What abnormal voltage and ride-through
operating requirements does the Company propose?
A. The Company proposes that for abnormal- voltage
events and ride-through capabillty, inverter-based DERs be
set to Category IIf.
0. Did the Company consider requesting additional
smart inverter functional-ities to be implemented?
A. Yes, but the Company decided not to request
additional smart inverter functionality requirements at
this time. Viith the current level of DER penetration on
its system, these proposed settings should provide t.he
necessary voJ-tage management capability. The Company
recommends a1l- other smart inverter settings be consistent
with the most recently approved IEEE 1541 standard
(currently IEEE t547-201-9) defaul-t settj-ngs.
O. WiIl- smart inverters reduce solar PV system
efficiencies and/or increase costs for customers?
A. Any irnpact
previously mentioned, the
will be negligible. As
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Company is proposing the smart
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Idaho Power Company
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inverters have a voltaqe-reactive function reactive power
control- setting with a voltage dead band between 0.98 and
1.03 pu. Distribution circuit operation outside of this
dead band will- be uncommon. Absorbing or providing vars
when outside of the dead band will require 1ittle to no
reduction in the production of the PV Solar system.
The alternative would be more costJ-y di-stribution
system upgrades to allow the operatj-on of the DER without
on-site var/voltage support.
0. What customer generators will- be required to
install a smart inverter?
A. The Company requests prospective customers
that submit an application on or after the effective date
of Schedule 68 comply with the smart inverter standard.
0. WiIl customers with existing generation be
required to retrofit their install-ations to comply with the
new standard?
A. No. However, if a customer replaces an
inverter, they woul-d be required to install an inverter
that is compliant with the terms of Schedule 68, or a
successor schedule, in place at that time.
IV. CUSTOMER GENERATTON NON-EXPORT OPEION
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23 O. What is
a customer generator
the Company proposing as it relates to
that does not export to the grid?
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Idaho Power Company
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A. The Company is requesting to implement
standard j-nterconnection requirements for customers who
seek to install DERs but who do not intend to export excess
net energy or do not wish to
Residential Service On-Site
take service under Schedule 6,
Generation ("Schedule 6"),
Schedul-e 8, SmalI General Service On-Site Generation
("Schedule B') or Schedule 84, Customer Energy Production
Net Metering Service ("schedule 84').
0. Does the Company have customers who have
interconnected generation in Parallel without taking
service under Schedule 6, 8, or 84?
A. Yes. I am aware of a few instances where
commercial or industrial ("C&T") customers have
interconnected either combined heat and power ("CHP") or
solar PV systems behind-the-meter, and in ParaIleI with the
Company's system, but whose request did not align wlth the
requirements contained within Schedule 84. Some of those
customers take service under the Company's Schedule 45,
Standby Service ("Schedul-e 45"), but at least one opted not
to take Schedul-e 45 service. I am aware of other customers
who have inquired about requirements for DERs that exceed
the limitations contained within Schedule 84, but who do
not desire to export excess net energy to the Company.
0. What interconnection requirements did t.he
Company require in those cases?
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ELLSWORTH, DI
Idaho Power Company
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1 A. In the cases I am aware of , t.he customers
2 contacted the Company to determine whether any specific
3 interconnection requirements were necessary, The Company
4 studied each case independently to determine whether
5 Company-furnished interconnection facilities would be
6 necessary or whether the customer-furnished interconnection
7 provided adequate system protection, metering, and
B communications equipment.
9 Q. Does Schedule 45 contain requirements for
10 interconnection facilities?
1l- A. Yes. Schedule 45 states:
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ParaIIeI operations will only be
authorized by the terms of the UniformStandby Service Agreement with the
Customer. At the Company's discretion,the Company will- install a systemprotection package at the Customer's
expense prior to the start of parallel
operations. The Customer will also pay
a Maintenance Charge of 0.59 percent per
month ti-mes the investment in theprotection package.
If the Company has interconnected a few0.
25 customers on a case-by-case basis, why does the Company
26 believe it is now necessary to have requirements outlined
27 in a tariff schedule?
28 A. The instances I mentioned have all
29 interconnected in approximately the last two to three
30 years, but the Company has fiel-ded multiple requests more
31 recently from customers desiring this type of service.
ELLSWORTH, DI
Idaho Power Company
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L Having these requirements defined in the tarlff will assist
2 Lhe Company's representatives, installers, and customers,
3 alike who may be involved in discussions regarding
4 lnterconnecting generation in this manner and wir-r ensure
5 consistent treatment across the service area.
6 Q. What interconnection requirements does the
7 Company propose for non-export customers?
I A. The Company, s proposal would require customers
9 intending to interconnect a non-exporting system in
10 Paralrel to the company's system to submit an application
11 and complete the Customer Generator Interconnection Process
72 set forth in the proposed Schedule 68. The same generar
13 requirements would apply to net metering exporting systems
t4 and non-exporting systems, including disconnection
15 equipment, metering equipment, and smart inverter
16 requirements- For non-exporting systems under 3 megavolt-
t7 ampere ("MVA') total nameplate capacity, the application
18 process will al-so generally be the same as those for
19 exporting systems.
20 The Company has included additional interconnection
2l requirements specific to non-exporting systems in sections
22 3 and 4 of Schedule 68. Non-exporting systems wou1d be
23 required to incorporate one of three listed non-export
24 control system options: (1) advanced functionality, (2)
25 reverse power protection, or (3) minimum power protection.
ELLSWORTH, Dr l_B
Idaho Power Company
1 0. What is an advanced functionality non-export
2 control system?
3 A. The use of an internal transfer re.Iay, energy
4 management system, or other customer facility hardware or
5 software system(s) may be used to ensure power is never
6 exported across the interconnection point. Inverter-based
7 generation technologies, such as solar PV or energy storage
8 devices, are particularly Iikely to utilize this control
9 system. ff inverter-based, the generating facility must
10 utilize smart inverters as defined in Schedule 68.
11 As described in Schedule 68, the non-exporting
L2 system must monitor the total inadvertent export, and the
13 DER must disconnect from the Company's distribution system
14 or halt energy production within two seconds after the
l-5 period of continuous inadvertent export exceeds 30 seconds.
16 The non-exporting system must enter a safe operating mode
77 where inadvertent export will- not occur as a resu1t of a
18 failure of the control or inverter system for more than 30
19 seconds, which results in loss of control signal, Ioss of
2A control power or single component failure or related
2L control- sensing of the control circuitry.
22 0. What is a reverse power protection non-export
23 control system?
24 A. To ensure power is never exported, a reverse
25 power relay protective function musL be implemented at the
ELLSWORTH, Dr 19
Idaho Power Company
1 interconnection point. As described in Schedule 68, the
2 default setting for this protection equipment shall be 0.1
3 percent (export) of the non-exporting systems total maximum
4 nameplate capacity, measured in terms of either kVA or MVA,
5 with a maximum two-second time delay.
6 Q. What is a minimum power protection non-export
7 control system?
8 A. To ensure at least a mlnimum amount of power
9 is imported at all times, and therefore, that power is not
10 exportedr dD under-power protective function may be
11 implemented at the interconnection point.. As set forth in
L2 Schedul-e 68, the default setting for this non-export
13 control system shall be five percent (inport) of the non-
L4 exporting systems total maximum nameplate capacity (kVA or
15 MVA), wi-th a maximum two-second time delay,
16 a. Do you believe these requirements wil-l- be
17 burdensome for customers seeking to interconnect non-
18 exporting systems?
19 A. No. Approximately 99 percent of active net
20 metering systems on Schedule 5, B, and 84 are inverter-
21 based generation resources. Therefore, the Company would
22 expect that most customers electj"ng for the non-export
23 option would choose to implement the advanced functionality
24 for their non-export control system. As a result, this
25 woul-d not result in an incremental expense for the
ELLSWORTH, DI 2Q
Idaho Power Company
1 customer. The other two non-export control options are
2 provided for the rare instances where utilizing the
3 advanced functionality is not a feaslble non-export control
4 option.
5 Q. Does the Company propose limiting the total-
6 nameplate capacity for non-exporting syst.ems?
7 A. Not in most instances. The net metering
8 service avaifable to exporting commercial, industrial, and
9 irrigation (*CI&I") customers under Schedule 84 is limited
L0 to 100 kVA. For CI&I customers with non-exporting systems,
l-1 the total nameplate capacity woul-d not be l-imited.
12 Customers on Schedules L and 7 would be limlted to a total
13 capacity of 25 kVA.
14
15
L6
1,7
18
19
20
2L
22
Why is it
1 and 7, but
A. Generally, customers taking service under
Schedule l- or 7 will not have a load large enough to
warrant a system larger than 25 kVA to offset their
consumption. Further, placing a system cap on Schedufe 1
and 7 will al1gn with the namepJ-ate capacity limits in
Schedul-e 6 and 8 to all-ow for customers to transition
between the applicable net metering and non-export service
23 schedu]e.
24 0 Would CI&I customers be able to transition
25 from a non-export optlon to Schedule 84?
ELLSWORTH, DI
Idaho Power Company
nameplate
o.
Schedules
reasonable to include Iimitations on
not on other service schedules?
2L
1
2
3
A. If
capacity of 100 Iess, they would have
84 in the same manner
the ability to
as a non-
the CI&I customer has a total nameplate
kVA or
transition to Schedule
4 exporting customer generator can transition from Schedule 1
5 or 7 to Schedule 6 or 8, respectJ-vely.
6 O. Does the Company propose any other
7 requirements speciflc to customer generation non-exportlng
8 systems?
9 A. Yes. Rotating machines up to 500 kVA total
10 nameplate capacity and inverter-based DERs up to 3 MVA may
11 not require additional Company-furnished protection
1,2 equipment but wiII be evaluated on a case-by-case basis.
13 For systems 3 MVA or larger, the Company will require
L4 protectlon equipment, metering, and communj-catj-ons
15 equipment.
16 O. Why does the Company propose protection
Ll equipment requirements for larger systems?
18 A. For rotating machines on the distribution
19 system, these larger systems provide a higher fault current
20 contribution. For j-nverter-based systems on the
21 distribution system, a DER of 3 MVA or greater represents a
22 significant amount of generation and will rnake up a minimum
23 of 30 percent of the capacity on a typical distribution
24 circuit. Both types of DERs can affect distribution
ELLSVIORTH, Dr
Idaho Power Company
22
l- circuit voltage levefs for other customers and can impact
2 operational safety and distribution circuit reliability.
3 The addition of protection equipment provides a
4 means to coordinate distribution circuit protection, such
5 as circuit breakers, reclosers, and fuses.
6 Protection equipment will also be utilized to
7 monitor voltage. A DER 3 MVA or greater has the ability to
8 absorb or supply 1.3+ mega-var of reactive power, which can
9 significantly impact the voltage on the distribution
10 system. Protection equipment for these larger projects
11- will ensure other customers on the feeder are protected
12 from issues that may arise with the DER 3 MVA or greater.
l-3 Finally, protection equipment provides a means to
t4 maintain safety and reliability. Idaho Power operational
l-5 personnel regularly maintain and operate distribution
16 circuit equipment and must be aware of these larger DgR
L7 installations when verj-fying de-energj-zed sectlons of the
18 circuit, or when transferring load between adjacent
19 distribution circuits.
2A 0. Why does the Company propose a metering and
2L communications equipment requirement for Iarger DER
22 systems?
23 A. The company is proposing a metering and
24 communications equipment requirement due to the system size
25 and the need for operational visibility t,o complete
ELLSVIORTH, DI 23
Idaho Power Company
1 critical- System Operations functj-ons. Visibility is
2 required for the purposes of scheduling, dispatching, and
3 load balancing.
4 For scheduling, the Company is responsible for
5 forecasting future system loads and resources. Actual data
6 from these customer sites wlth DERs 3 MVA and larger is
7 critical for maintai-ning and refining an accurate load and
8 resource forecast.
9 For dispatching, the Company's System Operators
10 frequently move customers from one distribution circuit to
11 another for operational and maintenance purposes. When
L2 shifting these customers, System Operators must consider
13 whether ANSI standard C84.1 can continue to be met if the
t4 large DER system suddenly reduces output, for example,
15 during a partly-cloudy day.
16 Finally, for load balancing, System Operators
1,7 maintain a reaL-time balance between system load and system
1B resources. Real-time information about the output of
19 larger system resources, such as DERs 3 MVA or greater,
20 provides important real-time visibility into what may be
2L causing an area control error deviation, and whether a
22 System Operator should take immediate actionr or wait for
23 the clouds to pass.
24 0. V{hat additional interconnection study
25 requirements does the Company propose specific to non-
ELLSWORTH, Dr 24
Idaho Power Company
1 exporting systems with a total nameplate capacity of 3 MVA
2 and greater?
3 A. The Company proposes that for non-exporting
4 systems with a total- nameplate capacity of 3 MVA or
5 greater, the Company will complete additional studies, as
6 needed, at the eustomer's expense. In addition to the
7 Feasibility Review completed for al-l DERs, non-exporting
8 systems 3 MVA or greater may also require one or more of
9 the following: Eeasibility Study, System Impact Study, and
10 a Facility Study. This process has been modifled from the
11 Generation Interconnection Process for PURPA Qualifying
L2 Facilities under Schedule 72 and is described in more
13 detail in Section 4 of Schedule 68.
L4 At the end of each stage of the study process, the
15 Company will provide the customer generator with an
76 increasingly more refined and detailed report that wilI
L1 present a list of necessary interconnection facil-ities.
18 The report would also include a non-binding, good faith
L9 estimate of the customer generator's cost responsibillty
20 for the interconnection facilities. The Company expects
2L the need for a System Impact Study will be rare and
22 reserved for the most complex projects.
23 O. Why does the Company propose that non-
24 exporting systems 3 MVA or greater complete a ful-l Customer
25 Generator Interconnection Process?
ELLSWORTH, DI
Idaho Power Company
25
1
2
3
4
5
6
1
8
9
A Due to their they can significantlysize,
Thegrid's
these
affect the voltage.process proposed by the
completeCompany
the fu1l
for larger non-exporting systems to
Customer Generator fnterconnection Process and
ELLSWORTH, DI
Idaho Power Company
l_0
O. Why must non-exporting systems have similar
performance characteristics compared to any other
generation system?
A. An example of this is during a transient
condition thdt resu.Lts in extremely 1ow voltage (down 0.88
to 0.50 pu) ; the non-exporting system is required to
continue operation for up 20 seconds. The non-exporting
system operati-on, combined with other on-grid DERs, is
required to remain connected to avoid a sustained system
outage.
A. WiII non-exporting systems 3 MVA or greater
need to enter Idaho Power's generation interconnection
2L queue?
22
sign a uniform interconnection agreement recognizes they
characteristics compared tomust have similar performance
any
72.
other generation system int.erconnected under Schedule
A. No. These DERs
therefore, will- not enter the
interconnection queue.
are non-exporting systems and,
Company's generation
l-1
L2
13
L4
15
1,6
L1
1B
19
20
23
24
26
1
2
3
4
5
6
1
8
9
0. When it
j-s necessary, how does
wifl be funded?
is determined that system protectj-on
the Company propose those upgrades
A. The Company will instal-l a system protection
package at the customer/ s expense, and the customer will
pay a maintenance charge of 0.59 percent per month times
the investment in the protection package. Ilrlhile general
upgrades on the distribution system are funded pursuant to
RuIe H, in the case of System Protection, the Company
proposes the customer will pay the actual 1nstalled cost of
the system protection equipment. This funding mechanism is
similar to what is provided for under the Company's
Schedule 45, Standby Service under the Paral-Iel Operations
section.
0. WilI the Company require a Customer Generator
with a non-exporting system to fund upgrades on the
Company's distribution system if the non-exporting system
totat nameplate capacity exceeds the capacity of the local
dlstribution facilities ?
A. No. The Company initiall-y considered
requesting tariff language that would require, for example,
a Schedule 6 or I non-exporting customer to pay for a
transformer upgrade if the system size exceeded that of the
transformer. After considering feedback received from the
Commission Staff and Idaho Clean Energy Association
ELLSWORTH, Dr 27
Idaho Power Company
10
11
12
13
14
15
t6
1,7
18
19
20
2L
22
23
24
25
l- ("ICEA"), the Company opted to instead propose adding
2 cLarifying language to the tariff schedule that would
3 require a customer to replace any damaged equipment if
4 failure of the non-export control system resulted in damage
5 to the ComPanY's sYstem.
6 Q. How does the Company propose to define the
7 failure of the non-export control system?
8 A. Under the language proposed in Schedule 68, an
9 unauthorized inadvertent export would conclusively indicate
10 non-export control system failure. Unauthorized
11 inadvertent export would be defined as the total exports in
12 any 3O-day period exceeding three hours of the total
13 nameplate rating. The total nameplate ratlng is specified
14 on the System Verification Eorm for a customer generator
15 system. As an example, a 10 kVA AC system would be limited
15 to 30 kWh of export in 30 days. If more than 30 kwh of
t1 export occurs, the non-export control system would have
18 failed.
19 O. What process does the Company propose to
20 mitigate cases of unauthorized inadvertent export?
21, A. The Company would notify the non-exporting
22 customer that their customer generation system has exceeded
23 the inadvertent exPort limit.
24 For Schedule 1 and Schedule 7 customers, if not
25 rectified within 30 days after receipt of the notification
ELLSWORTH, DI 28
Idaho Power ComPanY
1
2
3
4
5
6
1
B
9
by ldaho Power, the customer can efect to disconnect the
non*exporting system from the grid until the issue that
caused the export is remedied. An Idaho Power inspection
would be required before the non-exporting system eould
interconnect to the system again. If the customer instead
chooses to take service under Schedules 6 or B, the
customer would complete the application process and be
placed on Schedul-e 6 or Schedul-e 8, as appropriate. If the
customer is placed on Schedule 6 or Schedul-e 8, the
customer will be given the option to submit an additional
application and be moved back to Schedule L or Schedule 7,
as approprj-ate, after 180 days,
For customers on Schedules other than Schedule 1 or
Schedufe '1, upon notification from fdaho Power, the non-
exporting system will be disconnected from the grid until
the issue that caused the export is remedied. A Company
inspection will- be requlred before the non-exporting system
can safely j-nterconnect to the Company's system.
V. ENERGI STORAGE DE\TICES
t_0
l_ l_
1,2
l_3
t4
15
16
L7
18
L9
20 a. Why is the Company proposing to define energy
storage devices, such as batteries, in Schedule 68?
A. Customer instal-lations of energy storage
devices are growi-ng, While energy storage devices are
DERs, they are typically instal-1ed by customers for the
2L
22
23
ELLSWORTH, DI
Idaho Power Company
24
29
1 purposes of backup power or time-shifting energy from an
2 on-site generation facillty.
3 Establishing criteria in the tariff will best enable
4 the Company, installers, and customers to understand what
5 interconnection requirements are applicable to batterj-es,
5 just as it does today for generation facilities.
7 Q. Is the Company prosing to include additional
B interconnection requj-rements for energy storage devices?
9 A. Under the Company's current proposal, there
10 would be no additional requirements for energy storage
11 devices DC coupled to another generation system (shared
12 inverters). The system size will be determined by the
13 inverter nameplate rating.
L4 Energy storage devices which are AC coupJ-ed
15 (separate inverters) with a generation facility on Schedule
15 6, 8, or 84 will be treated as a separate DER and require a
17 separate application and interconnection review. The total
18 system size will be determined by the aggregate value of
19 all separate inverter nameplate rati-ngs at the customer's
20 premise.
2L Energy storage devices which are AC coupled
22 (separate inverters) with a non-exporting system or
23 installed on a stand-alone basis would be subject to the
24 provisions of Schedule 68, Section 3 for non-exporting
25 systems. Eor an energy storage device to not export, it
ELLSWORTH, DI 30
Idaho Power Company
1
2
3
4
5
will be required to
Option 1 (Advanced
u
implement non-export control system
Functj-onaf ity) .
A
Does this conclude your testimony?
ELLSWORTH, DI
Idaho Power Company
31
1
2
3
4
5
6
7
8
I
DECLARA:IIOII OF ilared L.
I, Jared L. Ellsworth, declare
E].lguorth
10
perjury under the l-aws of the state of
under penalty of
Idaho:
1. My name is Jared L. Ellsworth. I am
employed by Idaho Power Company as the Transmission,
Distribution & Resource Planning Director for the Planning,
Engineering & Construction Department.
2. To the best of my knowledge, my pre-filed
direct testimony and exhibits are true and accurate.
I hereby declare that the above statement is true to
the best of my knowledge and belief, and that I understand
it is made for use as evidence before the Idaho Public
Util-ities Commission and is subject to penalty for perjury.
SIGNED this 20th day of July 2020, at Boise, Idaho.
.f dL Ellsworth
ELLSWORTH, DI
Idaho Power Company
11
L2
13
14
15
16
1't
32