20200720Aschenbrenner Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
rN THE MATTER OF IDAHO POWER
COMPANY' S APPLICATION FOR
AUTHORITY TO ESTABLISH TARIFF
SCHEDULE 68, TNTERCONNECTTONS TO
CUSTOMER DISTRIBUTED ENERGY
RESOURCES
IDAHO POWER COMPANY
DIRECT TESTIMONY
CONNIE G. ASCHENBRENNER
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CASE NO. IPC-E-20.30
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0. Please state your name, business address, and
present position with ldaho Power Company ("Idaho Power" or
ttCompany" ) .
A. My name is Connie G. Aschenbrenner. My
business address is 1221 lllest Idaho Street, Boise, Idaho
83702. I am employed by Idaho Power as the Rate Design
Senior Manager in the Regulatory Affairs Department.
O. Pl-ease describe your educational background.
A. In May of 2006, I received a Bachelor of
Business Administration degree in Einance from Boise State
University in Bolse, Idaho. In December of 2071-, I earned
a Master of Business Adminlstration degree from Boise State
University. In addition, I have attended the electric
utility ratemaking course The Basics: Practical Regulatory
Training for the Electrlc Industry, a course offered
through New Mexico State Unj-versity's Center for Public
Utilities.
O. Pl-ease describe your work experience with
Idaho Power.
A. In 2A\2, I was hired as a Regulatory Analyst
in the Company's Regulatory Affairs Department. My primary
responsibil-ities included support of the Company's
Commercial and Industrial customer class's rate design and
general support of tariff rules and regulations. In 2015,
I assumed responsibilities associated with Residential and
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Idaho Power ComPany
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1 Small General- Service rate design, as well as activities
2 associated with demand-side management ("DSM") activities.
3 fn 20L6, I was promoted to a Senior Regulqtory Analyst, and
4 my responsibilities expanded to include the development of
5 compLex cost-related studies. In 201.1, I was promoted to
6 Rate Design Manager for ldaho Power, and in 20L9 I was
7 promoted to my current role as Rate Design Senior Manager.
8 I am currently responsible for the management of the rate
9 design strategies of the Company, as well as oversight of
l-0 a1l- tariff administration.
11 O. 9{hat is the Company requesting in this filing?
L2 A. The Company is requesting to establish tariff
l-3 Schedule 68, Interconnections to Customer Distributed
1,4 Energy Resources ("Schedule 68"), included as Attachment
15 No. 1 to the Application, and to modlfy Schedule 72,
L6 Interconnections to Non-Utility Generation ("Schedule '12"),
L7 to remove only the provisions of Schedule 72 that relate to
1B retai1 customer generati-on interconnection requirements.
19 Attachment Nos. 2 and 3 to the Appllcation include redline,
20 legislative format and clean copies of Schedul-e 12,
2L respectively.
22 0. What are the primary objectives of the
23 Company's request?
24 A. The primary objectives of the case are to
25 implement an interconnecti-on tariff schedule applicable
ASCHENBRENNER, DI
ldaho Power Company
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only to retail customers who have Distributed Energy
Resources ("DER" or "DERs"), establish a smart inverter
standard for aII new DER interconnections, and establish
interconnection requirements for customers with DERs who do
not wish to export excess net energy to the Company.
O. fs Idaho Power requesting any changes to
interconnection requirements contained in Schedule 72
applicable to SeIIers owning or operating Qualifying
Facilities that sign a Uniform Interconnection Agreement?
A. No. The Company's request in this case only
addresses interconnection requirements for generation
facilities that qualify for Schedule 6, Residential Service
On-Site Generation ("Schedule 6"), Schedule 8, Small
General Service On-Site Generation ("Schedule 8"1, or
Schedu1e 84, Customer Energy Production Net Metering
Service ("Schedule 84") and those retail customers of Idaho
Power desiring to install a non-exporting system.
O. Why is the Company proposing to address the
interconnection requirements for retail customers with DERs
at this time?
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2l A. The Company
22 Commission orders issued
submits this filing in response to
in Case No. IPC-E-17-13. In Order
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No, 34046, the Commission
provide functionality that
found that "smart inverters
is beneficial to support the
of the Company's
ASCHENBRENNER, DI
Idaho Power Company
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distribution system" and a "smart inverter requirement will
mitigate circuit voltage deviation in a cost-effective
manner." As such, the Commission ordered the Company to
file a tariff advice with the Commission within 60 days of
the final adoption of the Institute of Electrical and
El-ectronics Engineers (*IEEE") standards L547 and 1547.1.
The final IEEE 1,547.1 Standard Conformance Test. Procedures
for Equipment Interconnecting Distributed Energy Resources
with Electric Power Systems and Associated Interfaces was
published on Nlay 2L, 2424.
Further, in Order No. 34147 issued j-n the same case,
the Commission stated it was "open to the possibility of
allowing the customer opportunlty to remove himsel-f from
the Company's net metering schedul-es" if that "customer can
reasonably and safely eliminate the export of energy to the
Company's grid. " The Commission ultimately ordered, "a
non-export option should be studied for feasibility and
vetted for safety and operational concerns by the Company
and interested stakeholders in the forthcoming docket. "
0. How is the Company's case organized?
A. My testimony wiII (1) brj-ef1y describe
relevant case history related to the existing
interconnection requirements applicabLe to customer
generation, smart inverters, and the non-export option, (2)
explain the rationale for implementing Schedule 68 and
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Idaho Power Company
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l- removing retail customer generator interconnection
2 requirements from Schedu.l-e 72, (3) outline the proposed
3 changes to existing tariff provisions applicable to retail
4 customer applicants and existing customer generators, and
5 (4) provide a brief overview of customer and installer
5 communication rel-ated to this request.
7 Company witness Jared Ellsworth's testimony wlII (1)
8 provide a general overview of the Company's electrical
9 system and how customers with DERs utilize the Company's
10 distribution system, (2) describe the Company's request
11 related to incorporating the smart inverter requirement,
12 (3) explain the Company's proposal for requirements for
13 customers who desire to interconnect non-export systems in
74 parallel with Idaho Power's system, and (4) describe the
15 Company's proposed requirements for energy storage devices.
16 I. BACKGROI'IID
77 [aterconaeetiora Reqroireanata
18 O. When was Schedule 72 initially established,
19 and what was its purpose?
20 A. On April 12, 1.991, the Commission issued Order
2L No. 23637, implementing Schedule 12 to be applicable to
22 small- and large non-utility generating facilities seeking
23 to interconnect to Idaho Power's system for the purpose of
24 se11lng energy.
ASCHENBRENNER, DI
fdaho Power Company
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1 Q. When was Schedule 72 initially modified to
2 incorporate requirements associated with on-site generation
3 installed by retail rate customers?
4 A. On November 9, 2001., the Company filed Case
5 No. IPC-E-01-39 seeking approval of a new tariff Schedule
6 84, Customer Energy Production, Net Metering Service
7 ("schedule 84'). concurrent with that filing, the company
I filed two additional cases: (1) Case No. IPC-E-01--40 in
9 which the Company sought to eliminate the net metering
l-0 option language in Schedule 86 (contained in Option B of
1l- Schedule 86 at that time), and (2) Case No. IPC-E-01-38 in
12 which the Company sought to establish the interconnection
13 requirements for net metering customers within Schedule 72.
14 O. What were the outcomes of those cases?
15 A. In Case No. IPC-E-01-39, the Commission issued
16 Order No, 28951 approving the Company's request to incl-ude
L7 a net metering offering in Schedule 84, which would
18 initially be avaj-1ab1e to residential and smal-1 commercial
19 customers seeking to interconnect on-site generation
20 systems 25 kilowatts ("kW") or smalfer. In Case No. IPC-E-
2L 01-40, the Commission (in Order No. 29093) approved the
22 Company's request to modify Schedule 86 to eliminate the
23 net metering option previously offered under that schedule.
24 Finally, in Case No. IPC-E-01-38, the Commission issued
25 Order No. 29092, approving streamlined interconnection
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Idaho Power Company
1" requirements for retail customer net metering projects to
2 be contained wlthin Schedule 72.
3 Q. Has Schedule 72 been modified subsequently to
4 incorporate necessary revisions for customer generation
5 offerings?
6 A. Yes. While not an exhaustive list, the
7 Company sought modifications to Schedule 72 in two net
B metering specific cases, Case Nos. IPC-E-12-21 and IPC-E-
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10 0. What changes to Schedule 72 did the Company
11 request in Case No. IPC-E-72-27?
L2 A. The Company requested several modifications to
13 Schedule 72 intended to improve clarity and increase
L4 customer understanding. The Company requested to
15 reorganize Schedule 72 to clarify sections applicable to
L6 net metering service, expand details around the application
l7 process for net metering customers, and outline a new
18 process to be applied to unauthorized net metering
19 installations.
20 O. Did the Commission approve the changes to
2L Schedule '72 requested in Case No. IPC-E-12-21?
22 A. Yes. In Order No. 32846, the Commission
23 approved the proposed settlement of the issues related to
24 interconnection in that case.
ASCHENBRENNER, DI
Idaho Power Company
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1 Q. What changes to Schedule 72 did the Company
2 request in Case No. IPC-E-17-13?
3 A. The Company requested revisions to Schedule '12
4 to incorporate the defined terms necessary to sync the
5 interconnection requirements between Schedule 72 and the
6 newly proposed Schedules 6 and 8.
7 Q. What position did parties to Case No. IPC-E-
8 17-l-3 take on the issue of the Company's requested
9 modifications to Schedule 72?
10 A. Both Commissi-on Staff and the Idaho Clean
11 Energy Association opposed the proposed revisions to
L2 Schedule 72. Commission Staff took the position that "the
13 Company's proposed modifications are not minor, and
14 constitute a major revision to ScheduJ-e 72" and because
L5 "Schedule 72 appJ-ies to all energy providers who
16 interconnect with the Company's grid, including its IPubIic
'J,1 Utility Regulatory Policies Act (*PURPA")l
18 j-nterconnecti-ons" the Company's proposed changes should be
l-9 considered in a separate case that would ensure input from
20 afl stakeholders."
2I O. Did the Commission ultimately approve changes
22 to schedule 72?
23 A. Yes. In Order No. 34046, the Commission
24 directed the Company to meet with Staff and other
25 j-nterested parties before filing conforming tariff language
ASCHENBRENNER, D]
Idaho Power Company
1 for Commission approval. Fol-Iowing the Commission's order,
2 the Company scheduled a meeting with Staff and other
3 interested stakeholders to walk through its proposed tariff
4 changes, demonstrating the requested changes would not
5 modify requirements applicable to PURPA interconnections.
6 The Company subsequently filed its updated tariff schedule
7 sheets wlth the Commission's ordered effective date.
8 Saart lavectere
9 Q. ?{hat was the Company's request in IPC-E-17-13
10 related to smart inverters?
11 A. The Company reguested the Commission
L2 acknowledge that smart inverters provide functionality that
13 is necessary to support the ongoing stability and
L4 reliability of the distribution system by ordering the
L5 Company to submit a compliance filing (by way of an advice
L6 filing) to require a smart inverter that meets the
77 requirements defined in the revised IEEE standard.
18 O. Did the Commlssion approve the Company's
l- 9 request ?
20 A. Yes. fn Order No. 34046, the Commissj-on
2L directed Idaho Power to file a tariff advice within 60 days
22 of final adoption of IEEE standards 1547 and 1,541.1 for
23 investigation and final approval.
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Idaho Power Company
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Noa-Ezctrtort Optioa
O. Was the Commission's Order No. 34046
establishing ScheduLes 6 and 8 found to apply to non-
exporting customers?
A. In the near term, yes; however, in granting
reconsideration in Case No. IPC-E-17-13, the Commission
directed interested parties to file briefs discussing
whether a customer's ability to export energy should
determine if the customer should be included in the newly
establj-shed Schedules 6 and 8. After reviewing the
evidence and arguments presented in the briefs, the
Commission issued Order No. 34147 where it ordered that:
all- on-site generation customersclassified in Schedules 6 and I remain
there for now. However, we al-so find itis reasonable to provide an opportunityfor a customer to be an on-site generatorand not export its energy, therebydistinguishlng himself from a customer
who imports and exports energy.
The Commission went on to order that "a non-export
option should be studied for feasibility and vetted for
safety and operational concerns by the Company and
interested stakeholders in the forthcoming docket. "
0. Did the Company and parties eva.l-uate the
feasibility of a non-export option j-n Case Nos. IPC-E-18-1-5
and IPC-E-19-15?
ASCHENBRENNER, DI
Idaho Power Company
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1 A. Yes. Over the course of 2019, the Company
2 participated in roughly 13 meetings where parties to Case
3 Nos. IPC-E-18-15 and IPC-E-19-15 engaged in discussions
4 broadly related to the Company's customer generation
5 offerings. Through those discussions, the Company obtained
5 feedback related to a potential non-export option that
7 could be made available to customers who did not want to
I interconnect generation facilities under the provisions of
9 Schedules 6, 8, or 84.
10 O. Generally, what feedback did the Company
11 receive?
12 A. Parties were supportive of the Company
13 implementing interconnection rules for non-exporting
t4 customers. Ultimately, several areas of agreement were
15 reached related to the establishment of a non-export
15 provision in the Settlement Agreement filed in Case No.
l7 IPC-E-18-15, which was intended to apply to resldentiaf and
18 small general service customers:
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o Non-export customers may receive service under
Schedules 1 and 7;
r Before exercising the non-export option, a
customer must file an application demonstratingthe functj-onality and safety of the non-
exporting system;
o Capacity limits for non-export customers will
be the same as limitati-ons listed in Schedufes
6 and B; and
r If exports occur and are not rectified, a
process to either disabl-e the system or to
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Idaho Power Company
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transition the customer to the appropriate on-site generation schedule would apply.
Parties agreed on these broad principles and agreed
to continue discussions related to specifics of the
interconnection requirements in additional workshops.
O. Did the Company host additional workshops?
A. Yes. The Company hosted two meetings specific
to discussing a proposal for a non-export option. The
meetings were held at Idaho Power's corporate headguarters
building on October 23, 2019, and December 18, 20L9. A1I
parties to Case No. IPC-E-18-15 and Case No. IPC-E-19-15
were invited to attend one or both of those discussions.
A. Did the Company incorporate stakeholder
a.
implement
case ?
a new interconnection tariff schedule in this
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15 feedback into its recommendations in this case?
16 A. Yes. The Company's proposal related to the
L'l non-export option applicable to alI service schedules was
18 influenced by discussions with stakeholders. The Company
L9 believes 1ts proposal, as outlined in Mr. Ellsworth,s
20 testimony, balances providing enhanced customer optionality
21, while mitigating and monitoring system impacts that may
22 ul-timately impact other customers.
23 rI. REOI,EST TO IU T.ED@NT NEW I}RIFF SCHEDI'I,E 68
24 Pl-ease summarize the Company's rationale to
ASCHENBRENNER, DI
Idaho Power Company
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A.
applicable to
Establishing an interconnection schedule to be
customer DERs separate from the
interconnection requirements for Sellers on the Company's
system is intended to distinguish requirements applicable
to retail custmers of Idaho Power who intend to
interconnect DERs from requirements applicabl-e to Sellers
who seek to interconnect generation from Qualified
Facil-it.ies to the Company's system. The Company belleves
this will reduce confusion and procedural process when
parties are determining whether intervention and
participation in a case is necessary to protect or advance
their interests.
The Company believes separating the lnterconnection
requirements will- also reduce customer confusion,' in its
experience, some customers confuse which sections of
Schedufe '12 apply to their applications.
O. Are there differences in the interconnection
requirements for Idaho Power customers with DERs and those
Sellers who interconnect under Schedule 12?
A. Yes. While most of the physical
j-nterconnection requirements may be consistent, the
application process for retail customers with DERs is
distinctly different from a Seller seeking int,erconnection.
The funding for j-nterconnection facilities is a.l-so slightly
di-fferent,' Rule H applies to a retail cugtomer whose
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I request for service requires the installation of new or
2 upgraded distribution facilities, where a Seller under
3 Schedul-e 72 pays actual- work order costs for necessary
4 upgrades on the distributlon system. There are also
5 Federal Energy Regulatory Commission requirements that are
6 only applicable to Sellers and are not re1evant to customer
7 generators.
8 Q. You mentioned earlier that the Company is not
9 proposing any changes to Schedule 72 provisions that are
10 applicabl-e to Sellers as part of this filing. pl_ease
11 explain.
12 A. The Company is only requesting to remove the
13 provisions contained within Schedule '12 that apply to
L4 customer generators. The existing requirements and
15 application of those remain unchanged for Sel-lers seeking
16 to interconnect. Because of the removal of those sections
L7 only applicable to customer generators, the Company, s
l-B Schedule 72 would be shortened from 34 pages to 28 pages.
19 0. Did the Company discuss the proposal to remove
20 the requirements from Schedule 72 applicable to customer
2L generators with stakeholders in advance of this flling?
22 A. Yes. In both the October 23, 2019, and
23 December 18, 20L9 meetings, the Company discussed its plan
24 to create a new service schedule as I have described. The
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Idaho Power Company
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1 Company did not receive any opposition or feedback related
to this component of the Company's proposal.
0. trf,hen is the Company requesting Schedule 68 be
effective?
A. The Company requests Schedul-e 68 to become
effective 14-days after approval by the Commission. This
14-day implementation period is necessary to update
communication materials with any approved changes to the
interconnection requirements for customer DERs and provide
to installers and prospective customers.
III. UODIEICATIONS TO EXISTTNG INTERCONITECTIO}I REQUIREMENTS
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FOR RETAII. CUS:B6|ER DER
O. Does the Cornpany propose modifications to
facilitate and administer the interconnection of customer
DERs to its distribution system?
A. Yes. In preparation of the f i1i-ng to modif y
the inverter requirements and establish the non-export
interconnection requirements, the Company evaluated
existing processes to determine whether i-mprovemenLs could
be rnade to streamfine existing processes and/or i-ncrease
operational efficiencies or if changes were necessary to
ensure the Company can continue to meet the requirements
contained withln the tariff schedul,e.
Through that review, the Company identified severaf
opportuni.tles that it believes wiIl accomplish those goals:
ASCHENBRENNER, DI
Tdaho Power Company
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1 (1) modified or added language j-ntended to improve clarity
2 for the Company in administering and for customers and
3 installers in complying with the tariff schedule, (2)
4 removed the three-year recertj-fication requirement, (3)
5 added flexibility of additional time, only as needed, to
6 complete Feasibil-ity Reviews, (4) modified requirements in
7 the unauthorj-zed systems and expansions section, and (5)
I implemented a return-trip charge if the Company is unable
9 to complete an inspection.
10 0. Is the Company proposing to define any new
11 terms or create new processes in Schedule 68?
1,2 A. Yes. Mr. E1l-sworth's testimony introduces
13 several new definitions and proposed processes related to
14 incorporating smart inverters and interconnecting non-
15 export systems and energy storage devices. The supporting
16 rationale for each is contained in his testimony.
1,7 I4t.rovc Clarity
l-8 0. Why is the Company proposing to modify
19 Ianguage or provide additional- details in certain secti-ons
20 of the tariff scheduLe?
21 A. The last major revision to Schedule '12 was
22 proposed in 2013, as part of workshops in Case No. IPC-E-
23 12-27. At that time, the Company had approximately 350
24 existing and pending net metering customers and, through
25 discussions with installers and customers, identifled
ASCHENBRENNER, DI 16
Idaho Power Company
L several modifications that were necessary to better outline
2 expectations of the Company and of customer generators. In
3 the seven years that have passed since that last major
4 revision, the Company has interconnected or processed
5 approximately 6,500 net metering applications (as of June
6 30, 2020) . The Company's customer generatj.on team fields
7 and responds to thousands of phone calIs and emails each
B year, and through those conversations have identified areas
9 where the tariff language couLd be expanded to enhance
10 understanding. With these language changes, the Company is
11 not intending to implement new or different requirements,'
1,2 rather, it views these modifications as necessary to
13 improve clarity.
14 Rccortificatioa la^specti,oas
15 O. What is the requirement i-n the existing
16 interconnection tariff schedule regarding the
1,7 recertification of on-site generation systems?
18 A. Section 2 of Schedule 12 requires the
19 Company to perform a full recertification inspection of aII
2A on-site generation systems once every three years at no
21, charge to the customer. In addition to the mandatory
22 recertification, the existing tariff requi-rements provide
23 that the Company may inspect any net metering system at any
24 time if the Company identifies a condition that may be
ASCHENBRENNER, DI
Idaho Power Company
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1 unsafe or may otherwise adversely affect the Company, s
2 equipment, personnel, or service to its other customers.
3 Q. How long has the Company performed three-year
4 recertificatlons?
5 A. fdaho Power has performed three-year
6 recertifications since the net metering interconnection
7 requirements lrere initially established by the Commission
8 in 2002. At that time, the Company requested the
9 requirement for scheduled, periodic recertifications due to
10 concerns that may arise from a customer generator modifying
11 interconnection equipment in a manner that jeopardizes the
L2 integrity of the system.
13 0. What is the Company, s request in this case
L4 regarding periodic recertifications?
15 A. The Company requests to remove the mandatory
16 three-year recertification requirement, and instead,
1'1 authorize Idaho Power to conduct periodic inspections as
18 needed.
19 a. Why is the Company requesting to remove the
20 mandatory recertiflcation requirement?
2l A. In its experience, the Company identifies
22 issues, most commonly unauthorized system expansions or
23 disabl-ed systems, in only a small portion of the total
24 systems inspected during a recertification visit. The
25 Company has identified other means it can utilize, at a
ASCHENBRENNER, DI
Idaho Power Company
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t lower cost for customers, to identify locations where
2 changes have occurred without Company notification.
3 for example, it is now feasible to rely on reporting
4 from its Automated Metering Infrastructure (*AMI") to
5 identify whether a customer has expanded their system or
6 cases where a system may no longer be online, and this
7 could be done at a significant cost savings as compared to
8 rolling a truck to re-inspect the system. In addition to
9 relying on metering data, the Company may select a sample
10 based on region or resource type to monitor for and
11 identify any potential trends or issues that are identified
1,2 on re-inspection that could be addressed more broadly.
13 Considering the significant growth in customer
14 generation, the Company anticipates it wou.l-d be required to
15 perform approximately 1r800 re-inspections tn 2027, which
16 is projected to increase to 2,520 annual re-inspections by
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18 growth in customer generation and assumes no additional
19 growth. Modifying this requirement to provide Idaho Power
20 the opportunity to re-inspect in cases j-t believes may be
2L warrant.ed and eliminating the mandatory language will
22 result in increased operational efficiencies for the
23 Company and, ultimately, its customers.
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Idaho Power Company
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t Ee,aaibiJ.ity Reviarc
2 Q. How many days is the Company afforded to
3 complete a Feasibility Review?
4 A. Currently, the Company is requi-red, per
5 Section 2 of its Commission-approved Schedule 72, to
6 complete the Feasibility Review in seven business days.
7 Q. hlhat is the Company's request in this case
8 regardlng the completion of Feasibil-ity Reviews?
9 A. The Company requests the Commission allow
10 additional time in l-imited situations, where the Company
11 identifies that additional studies are needed to complete a
12 Eeasibility Review. fn those circumstances, the Company
13 requests that it be required to notify the applicant of its
L4 need for additional time and be required to complete the
15 Eeasibility Review within 15 business days.
16 O. lrlhy does the Company believe this additional
L7 flexibility is warranted?
18 A. The Company's existing Eeasibility Review is
L9 largely automated, and many applications "pass" the review
20 based on studied criteria (transformer size vs. system
2L size, phase compatj-bility, and project size vs. feeder
22 capacity). In those cases where the automated review
23 indicates an addltional review is necessary, the
24 appJ-ication is forwarded to an engineer in the Company's
25 Distribution System Planning department for further
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evaluati-on. As the volume of applications has increased,
and as the number of projects tied to the same transformer
or feeder increases, a more thorough and time-intensive
review is warranted.
The Company's ongoing ability to meet this
requirement has recently come into question, particularly
as the number of Schedule 24, Agricultural lrrigation
Service customers submitting requests for dozens of systems
located in the same geographical area has increased. For
these projects, the review team is expanded to include
multiple engi-neers, and coordination with engineers from
the regional offices is necessary. Modifying the
requirement to permit a more thorough review in complex
situatj-ons will ensure continued compliance with the
requirements of the tariff schedule.
Uaaathorized Systqs aud Ezqtaaaiona
O. V[hat are the current requirements when the
Company identifies an unauthorized system or system
expansion?
A. Sectj-on 2 of the existing Schedule 72 tariff
schedule provides for immediate Company inspection without
prior notj-ce. At that point, there are three potential
outcomes of the inspection:
r If proper disconnection equipment is present
(and it is in most cases), the Company wiII
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open and lock the disconnect. Within twenty-
four (24) hours of the disconnection, the
customer will- be caIled, and written
notification will be sent.
r If disconnection equipment is not present and
the customer's system utilizes a UL 1741 or
IEEE 7547 inverter, the customer is contacted
and given 15 days to submit an applicatj-on and
an additional 30 days to complete the necessary
inspection requirements or must notify the
Company within 30 days of their decision to
disabl-e thej-r system. Customers who fail to
take either action within the allotted
timeframe are subject to termination of
electric service.
. If no disconnection equipment is present and
the Company cannot verify the presence of a
compliant inverter, the customer is subject to
immediate termination of electric service.
O. How does the Company seek to modify the
requirements for unauthorized systems or system expansions?
A. As part of the newly proposed Schedule 68, the
Company recommends eliminating the requirement for Idaho
Power to "lock" a customer's system and is also requesting
the ttmeframes for either interconnecting a system under
ASCHENBRENNER, DI 22
fdaho Power Company
l- Schedule 6, 8, or 84 or disabling t.he system be extended.
2 The proposed Schedule 68 language would permit customers LZ
3 months to either complete the Customer Generator
4 Interconnection process or permanently disable the system.
5 The Company's proposed tariff language requires that
6 at any point during an installation (whether a new
7 application or a system expansion), a customer must keep
8 the system disconnected to separate the customer's
9 generation from the interconnected load until they have
10 completed the application process.
11 O. Why is the Company proposing these changes?
12 A. The current requirement for the Company to
13 "Iock" the system requires an Idaho Power employee to be
1,4 ca}led back on-site anytime a customer is working with an
15 instal-l-er or state inspector to bring the system back into
L6 compliance. Often, the Company may be called back multiple
L7 times. While locking the system provides for some
18 protection, the Company believes it is reasonabl-e to rely
19 on the customer and instal-l-er to keep the disconnect in the
20 open position, just as it does for al-I new systems that are
2l installed and awaiting inspection.
22 Through conversations with customers and installers,
23 the Company does not betieve the 45-day process outlined in
24 the current tariff schedule provides customers with a
25 reasonable opportunity to rectify the issues. Often, there
ASCHENBRENNER, DI 23
Idaho Power Company
l- are factors (e.9., staLe permitting, electrical
2 inspections, weather) outside the Company or customer, s
3 control that prevent these timelines from being met. The
4 Company belleves allowing 12 months (as provided for new
5 installations) more reasonably provides customers and
6 installers with an opportunity to rectify the issues.
7 Rctu-za-7;rip Chalrge
8 Q. What 1s the Company, s proposal regarding a
9 return-trip charge?
l-0 A. The Company is proposing to implement a $61.00
11 return trip charge for customers if the Company is unabLe
t2 to complete the inspection after the customer or instalter
13 has submitted a compl-eted System Verification Form
L4 certifying the system is ready.
15 O. Why is the Company proposing to implement a
16 return trip charge?
t7 A. The final step in the application process
18 occurs when a system has successfully completed the
1-9 Company's on-site inspection. Prior to the Company
20 dispatching a field resource to complete the inspectlon, a
2L customer must submit and sign a System Verification Form in
22 which the customer (or in many cases, the instal-ler acting
23 as an agent of the customer) certifies that the on-site
24 generation system is installed and that:
ASCHENBRENNER, DI
Idaho Power Company
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. The system meets all required codes and has
passed the city/stat.e electrical inspections;
o The system is operational, breaker and inverter
are engaged;
o The AC disconnect is in the open or off
position; and
o Required placards are in place.
fn approximately 10 percent of inspections between
2018 and year-to-date 2020, the Company has been unable to
complete the inspection once on-sj-te due to one or more of
these criteria that were incomplete despite certification
otherwise.
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0. What is the
to perform multiple trips
A. The Company
significance of the Company having
to perform an inspection?
is incurring incremental and
the short term, the Company is
avoidable,
customers.
unnecessary expenses.
allocating resources
and ultimately, this
fn
to perform visits that are
cost may be borne by other
O. What has the Company done to address the
issue?
A. The Company's customer generation team
communicates with new installers operating in Idaho Power's
service area to provide an overview of the application
process and interconnectj-on requirements, When the Company
identifies a specific issue with an installer, Idaho
ASCHENBRENNER, DI 25
Idaho Power Company
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Power's customer generatj-on team wilf contact the installer
to offer feedback and discuss the non-compliance, often
asking the installer to meet a Company-representative on-
site if more than two visits are required. In 20L8, the
Company updated its System Verification Form to include an
affirmative customer acknowledgment that the site was ready
to be inspected. FinaIly, the Company uses an electronic
newsletter, provided periodically to installers to
communicate about. repeat issues.
O. Have these enhanced communications been
effective at reducing the number of return trips in the
Company's
A.
service area?
No.Based on year-to-date 2020 data, the
return to perform an inspection in more
systems.
CUSTOD@R IND ITTSTAIJ.ER CODAiI'NICLSIO}I
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Company has had to
than 1-0 percent of
rv.
17 A. How wil-l the Company notj-fy install-ers and
18 customers of its request in this case?
l-9 A. The Company will send a communication directly
20 to installers known to be operating in its servj-ce area to
2L notify them of the request regardinq smart inverters.
22 Subsequent to this filing, the Company will also update its
23 customer generation webpage to include a summary of Idaho
24 Power's request in thls case and will maintain a List of
25 frequently asked questions to address common customer or
ASCHENBRENNER, D]
Idaho Power Company
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installer questions. fn addition to providing advance
notice of its intent to file this case, Idaho Power also
served its Application and testimony on the parties of
record in Case Nos. IPC-E-18-15 and IPC-E-19-15.
v. coNclusroN
a Please summarize the Company's request in this
case.
A. The Company requests that the Commission
authorize the Company to implement the proposed Schedule 68
interconnection tariff specific to retail customers with
DERs and remove the associated existing interconnection
provisions from Schedule 72. The Company requests Schedule
68 becorne effective 1"4-days after approved by the
Commission. The Company further requests that the
Commission approve proposed modifications to the
interconnection processes intended to improve efficiencies,
adopt the electric industry's smart inverter standard, and
outline provisions for interconnecting non-exporting
systems to the Company's system.
O. Does this concl-ude your testimony?
A. Yes.
ASCHENBRENNER, DI
Idaho Power Company
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1 DECI,ARATION OF CONNIE G. ASCEEIIBRTNIIER
2 T, Connie G. Aschenbrenner, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1-. My name is Connj-e G. Aschenbrenner. f am
5 employed by Idaho Power Company as the Senior Manager of
6 Rate Design in the Regulatory Affairs Department.
7 2. To the best of my knowledge, my pre-fi1ed
I direct testimony and exhibits are true and accurate.
9 t hereby declare that the above statement is true to
10 the best of my knowledge and bellef, and that I understand
11 it is made for use as evidence before the Idaho Public
L2 Utilities Commission and is sublect to penalty for
SIGNED this 20th day of July 2020, at Boise,
perj ury.
Idaho.13
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Cp,r*, Cfo,t ^ uy,ut,r.ru
Connie G. Aschenbrenner
ASCHENBRENNER, DI
Idaho Power Company
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