CHAPTER En 1000 DISTRIBUTED ENERGY RESOURCES INTERCONNECTION
PROCEDURES
PART En 1001 SCOPE
En 1001.01 Scope.
These interconnection procedures are applicable to all applications for distributed
energy resources seeking to interconnect to a New Hampshire utility. Such distributed energy resources shall
comply with RSA 362-A:9, X and XII.
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PART En 1002 DEFINITIONS
En 1002.01 “Affected system operator (ASO)” means the independent
system operator for the New England region, otherwise known as ISO New England,
and operators of other affected electric distribution systems (EDS).
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En 1002.02 “Affected system” means any distribution or
transmission electric power system other than the utility electric power system
(EPS), for which the stability, reliability, or operating characteristics might
be significantly affected by the proposed facility.
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En 1002.03 “Applicant” means the entity listed on the application
for interconnection to the utility EDS who serves as the general point of
contact for the application and otherwise assumes responsibility for the application
through issuance of the interconnection agreement (IA). The applicant can be the utility’s customer
of record or a third-party owner, operator, or developer of a facility.
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En 1002.04 “Application” means a request to have a
proposed facility interconnect to a utility EDS, or a request to modify an
interconnected facility.
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En 1002.05 “Authorization to interconnect” means an
official written notification provided by the utility to the interconnecting customer,
authorizing the applicant to activate and operate the facility subject to the
terms of the interconnection agreement or conditional approval of the interconnection
agreement, as applicable.
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En 1002.06 “Automatic sectionalizing device” means an
interrupting device, such as a line recloser, that can automatically
re-energize a line. A fuse is not an
automatic sectionalizing device. If
there are no line reclosers upstream of the facility, then the substation
circuit breaker is the next automatic sectionalizing device.
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En 1002.07 “Area network” means a specific area of the
EDS fed by multiple, parallel distribution facilities in a meshed configuration
with single directional power flow enforced by network protectors.
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En 1002.08 “Business day” means Monday through Friday
excluding state-recognized holidays.
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En 1002.09 “Certified” means a piece of equipment has
been tested in accordance with the applicable requirements of IEEE Std 1547™-2018, “IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 and IEEE Std
1547.1™-2020, “IEEE Standard Conformance Test Procedures for Equipment
Interconnecting Distributed Energy Resources with Electric Power Systems and
Associated Interfaces” dated 5/21/2020, by any nationally recognized testing
laboratory (NRTL) recognized by the United States Occupational Safety and
Health Administration to test and certify equipment pursuant to the applicable
standard and the equipment has been labeled and is publicly listed by such NRTL
at the time of the interconnection application.
Compliance with Supplement SB found in UL 1741 “Inverters, Converters,
Controllers and Interconnection System Equipment for Use with Distributed
Energy Resources” dated 4/22/2025 ensures compliance with IEEE Std 1547™-2018, “IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 and IEEE Std
1547.1™-2020, “IEEE Standard Conformance Test Procedures for Equipment
Interconnecting Distributed Energy Resources with Electric Power Systems and
Associated Interfaces” dated 5/21/2020. There
might be additional or separate certifications available for specific pieces of
equipment.
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En 1002.10 “Certificate of completion” means the form
required as proof that the applicant-facility has been constructed to satisfy
all applicable codes, standards, and requirements necessary for the facility to
interconnect to the EDS and reviewed and signed off on by the relevant
authority having jurisdiction.
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En 1002.11 “Commission” means the New Hampshire public utilities
commission.
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En 1002.12 “Common study area” means a discrete portion
of the company EPS where the operation of multiple interconnecting customers’ facilities
may have cumulative impacts. The company
needs to determine if interconnection applications fall within a common study
area. A common study area can include,
but is not limited to, an area that:
(a) Is fed from a common substation, or
(b) Is bounded by a circuit.
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En 1002.13 “Common system modification” means any system
modification that is required for more than one interconnecting customer’s facility
as determined by the company.
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En 1002.14 “Customer” means the person or entity that receives or
is entitled to receive service through the utility’s electric distribution
system (EDS) or is a retail customer of the utility.
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En 1002.15 “Department” means the New Hampshire department
of energy.
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En 1002.16 “Detailed study” means the final phase of
engineering study, if necessary, conducted by the utility to determine necessary
system modifications to its EDS, resulting in project cost estimates and a
construction schedule for such modifications that will be required for the facility
to interconnect to the EDS.
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En 1002.17 “Distributed energy resources (DER)” means distributed
generation and distributed storage.
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En 1002.18 “Distributed generation (DG)” means “distributed
generation” as defined in RSA 374-F:2, VIII.
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En 1002.19 “Electric distribution system (EDS)” means
the equipment operated and maintained by a utility to deliver electric service
to end-users, including and without limitation transmission and distribution
lines, substations, transformers, spot networks, and area networks.
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En 1002.20 “Exempt modification” means a modification to
an application or facility that does not increase the export capacity of the facility,
relocate the point of interconnection
(POI), or otherwise qualify as a material modification. These include, but are not limited to:
(a) A change of ownership of a facility;
(b) A change or replacement of generating
equipment, including inverters and transformers, that is a like-kind
substitution in size, ratings, impedances, efficiencies, or capabilities of the
equipment;
(c) Replacement of existing inverters with
inverters that conform to more recent standards after the state has adopted
their use, as long as the export capacity does not increase;
(d) Any change to equipment on the direct current
(DC) side of the applicant’s equipment, including DC coupled storage;
(e) Any change to relays or reclosers that do not
alter trip settings;
(f)
Modification to the grounding configuration that remains in compliance
with utility standards;
(g)
A change where the inverter dynamic simulation performance is equivalent
to the existing inverter; and
(h) A reduction in the size of the facility.
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En 1002.21 “Existing DER” means a DER that is
interconnected with the utility EDS and operating in parallel with the EDS.
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En 1002.22 “Export capacity” means the maximum nameplate
rating of a facility in alternating current (AC), except where the export
capacity is limited by any of the methods identified in En 1013.03, the export
capacity is the net capacity as limited through the use of such methods not
including inadvertent export.
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En 1002.23 “Facility” means a DER or proposed DER that
is located on the customer’s side of the point of common coupling.
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En 1002.24 “Fault current” means electrical current that
flows through a circuit and is produced by an electrical fault, such as phase
to ground, double-phase to ground, 3-phase to ground, phase-to-phase, and 3-phase. A fault current is often several times larger
in magnitude than the current that normally flows through a circuit.
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En 1002.25 “Group” means 2 or more applicant-facilities
by the same or different interconnecting customers in a common study area to be
studied simultaneously with agreement of all group member-applicants.
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En 1002.26 “Group study” means a single study that can be
performed at the same time for a group, instead of each interconnection application
undergoing such study separately either sequentially or in parallel as
determined by the utility.
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En 1002.27 “Group window” means the period during which
an applicant can elect to participate in a group.
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En 1002.28 “Institute of Electrical and Electronics
Engineers (IEEE)” means the Institute of Electrical and Electronics Engineers.
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En 1002.29 “Inadvertent export” means the unintentional
and unexpected export of active power from the facility to the utility EDS,
exceeding a specified magnitude and for a limited duration pursuant to En 1013,
generally due to load following behavior.
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En 1002.30 “Inadvertent import” means the unintentional
and unexpected import of active power from the utility EDS to the facility,
exceeding a specified magnitude and for a limited duration pursuant to En 1013.
Inadvertent import includes power flow conditions resulting from a fault
condition on the utility EDS.
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En 1002.31 “In-service date” means the date on which system
modifications, if applicable, are complete and the facility is interconnected
to the EDS and has been granted PTO from the utility, even if the facility is
not actively operating by that date.
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En 1002.32 “Interconnecting customer” means the entity
that owns either a proposed facility that is the subject of an application or
an existing DER with legal authority to enter into agreements regarding the
construction, modification, and operation of the facility or existing DER.
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En 1002.33 “Interconnection agreement (IA)” means the standard agreement
establishing the terms of connecting an applicant’s facility to the utility EDS
and entered into by the interconnecting customer and the utility. The agreement also includes terms and
conditions, attachments describing the facility, system modifications, payment
terms, and construction schedule, if applicable, and any subsequent amendments
or supplements to which the utility and interconnecting customer agree.
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En
1002.34 “Interconnection equipment package”
means a group of components connecting a facility with an EDS, and includes all interface equipment including switchgear, protective
devices, inverters, or other interface devices. An interconnection equipment package can include an integrated generator or electric source.
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En
1002.35 “Interconnection facilities”
means the electrical wires, switches, and related equipment that are required,
in addition to the facilities required to provide electric distribution service
to a customer, to allow interconnection.
Interconnection facilities can be located on either side of the point of
common coupling as appropriate to their purpose and design. Interconnection facilities can be integrated
to a facility or provided separately. Interconnection
facilities can be owned by either the interconnection customer or the utility.
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En 1002.36 “ISO New England, Inc. (ISO-NE)” means the independent
system operator established in accordance with the New England Power Pool agreement
and applicable Federal Energy Regulatory Commission approvals, which is
responsible for managing the bulk power generation and transmission systems in
New England.
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En 1002.37 “Line section” means that portion of the utility’s EDS connected to a facility
bounded by automatic sectionalizing devices or the end of the distribution
line.
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En 1002.38 “Material modification” means a facility
modification that is determined by the utility to be an electrically relevant change
to the POI, or any modification that requires the utility to reperform a SIS, group
study, detailed study, or a substantive simplified process or fast track
technical screen for the facility proposed to be modified or any facility
behind it in the queue. Material modification
does not include an exempt modification.
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En 1002.39 “Member impact modification” means a
modification to an application, applicant-facility, or existing DER that
results in delays to a group study or the implementation of system
modifications following a group study or increases the total cost of a group
study or the common system modifications.
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En 1002.40 “Nameplate
rating” means the total of maximum continuous power output capacity listed by
the manufacturer of all of a facility’s constituent generating or storage
units, regardless of whether it is limited by any of the methods in En 1013.03.
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En 1002.41 “Permission
to operate (PTO)” means authorization by the utility to the applicant to commence
generation and export power or operate in parallel with the EDS.
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En 1002.42 “Point
of common coupling (PCC)” means the point where the interconnecting customer’s
local electric power system connects to the utility EDS, such as the electric
power revenue meter or utility’s service transformer. The PCC shall be specified in the IA.
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En 1002.43 “Point
of interconnection (POI)” means the point where the interconnection facilities
connect with the utility’s EDS. This could
or could not be coincident with the PCC.
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En 1002.44 “Power
control system (PCS)” means systems or devices which electronically limit or
control steady state currents to a programmable limit.
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En 1002.45 “Pre-application
report” means a non-binding report of certain information
provided to the applicant by the utility prior to submission of the application
pursuant to En 1006.02.
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En 1002.46 “Protective function” means the equipment,
hardware, and software in a facility, whether discrete or integrated with other
functions, whose purpose is to protect against conditions that, if left
uncorrected, could result in harm to personnel, damage to equipment, loss of
safety or reliability, or the facility’s operation outside pre-established
parameters required by the IA.
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En 1002.47 “Queue”
means the sequential list of applications maintained by each utility pursuant to En 1004.03.
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En 1002.48 “Reference point of applicability (RPA)”
means a point suggested by an applicant from where a proposed facility should
be studied.
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En 1002.49 “Screen” means criterium by which the utility
will determine if a proposed facility’s installation will adversely impact the utility
EDS in the simplified and fast track processes pursuant to En 1007 and En 1008.
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En 1002.50 “Spot network” means a section of an electric
delivery system that uses 2 or more inter-tied transformers to supply an
electrical network circuit. A spot network
is generally used to supply power to a single utility customer or to a small
group of utility customers and has the same meaning as the term is used in IEEE
Std 1547™-2018,
“IEEE Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power System Interfaces” dated 4/6/2018.
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En 1002.51 “System
impact study (SIS)” means an engineering planning study performed by the utility
to determine the impact of the facility on the utility EDS and any necessary system
modifications to safely and reliably interconnect the facility to the EDS.
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En 1002.52 “System
impact study agreement (SISA)” means the agreement between the applicant and utility
detailing the scope, terms, and cost of the SIS and estimated schedule of
completion with progress milestones.
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En 1002.53 “Technical interconnection requirements (TIR)”
means public documents, often utility-specific, which
include requirements for interconnection, interoperability, DER capabilities,
and their utilization settings, and grid integration. Grid integration includes, but is not limited
to, protection coordination, and telemetry.
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En 1002.54 “Utility”
means the company that owns and operates the distribution facilities
delivering electricity to the customer’s premises and subject to the jurisdiction of the department and the commission.
For the purpose of this chapter, the
term utility does not include a rural electric cooperative for which a
certificate of deregulation is on file with the commission.
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PART En 1003 ORDER OF REVIEW
En 1003.01 Optional Pre-Application Report. Prior to submitting an application, a
potential applicant shall have the option to request a pre-application report
from the utility pursuant to En 1006.
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En 1003.02 Interconnection Review. There shall be 3 interconnection review paths
which are the simplified process, fast track process, and standard process. Within the simplified process and fast track
process there shall be options to undertake supplemental review and an applicant
options meeting prior to entering standard process. Any applicant may elect to be placed in standard
process or to move into standard process during application processing. The utility shall process the applications in
the order of their queue position as established pursuant to En 1004.03 unless
the application is part of a group study pursuant to En 1012.
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En 1003.03 Interconnection Review Paths.
(a) The simplified process shall be for certified
inverter-based facilities that have a nameplate rating of 50 kilowatts (kW) or
less and an export capacity of 25 kW or less. If the facility’s export capacity is not
limited, the nameplate rating shall not exceed 25 kW.
(b)
The fast track process shall be for facilities that have an export
capacity of up to one megawatt (MW).
(c)
The standard process shall be for all other facilities that do not
qualify for, or pass through, the simplified process or fast track process.
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PART En 1004 APPLICATION SUBMISSION AND PROCESSING
En 1004.01 Submission. All applicants shall be required to pay an
application fee consistent with the application fees adopted by the commission
and located in each utility’s retail distribution tariff. The applicant shall submit the application to
the utility along with the applicable application fee, regardless of whether
the facility plans to net meter.
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En 1004.02 Completeness Review. The utility shall record the date and time of
the application’s receipt. The utility
shall notify the applicant within 3 business days that the application has been
received. Within 10 business days of
receipt, the utility shall notify the applicant whether the application is
complete. If the application is
incomplete, the utility shall provide the applicant with a list of all
information that the applicant needs to provide to complete the initial application. The applicant shall provide the requested
information within 10 business days for the simplified and fast track processes
and 20 business days for the standard process, or the application shall be
deemed withdrawn.
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En 1004.03 The Queue. The utility shall assign the application a queue
position once it is deemed complete pursuant to En 1004.02. The utility shall maintain a queue for all facilities
evaluated under the standard process, which may be sortable by geographic
region, for example feeder or substation.
The queue shall be publicly available on the utility’s website, shall be
updated at least monthly, and shall contain the following information:
(a)
Project ID number;
(b)
Nameplate rating in kW;
(c)
Export capacity in kW;
(d)
Primary fuel type, for example solar, wind, or bio-gas, if applicable;
(e)
Energy storage rating in kW, or not applicable;
(f)
Energy storage capacity in kWh, or not applicable;
(g)
Energy storage coupling either AC, DC, or not applicable;
(h)
Town or city;
(i)
Substation;
(j)
Feeder;
(k)
Status, for example whether active, withdrawn, or interconnected;
(l)
Name of group study, if applicable;
(m)
Date application deemed complete;
(n)
Date of execution of SISA;
(o)
Date of notification of SIS, if readily available;
(p)
Date of notification of detailed study results and construction
estimates, if applicable and readily available;
(q)
Identifier of ASO group, if applicable;
(r)
Date final IA is issued to applicant;
(s)
Date IA is fully executed by the signature of both parties; and
(t)
Date of grant of permission to operate.
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En 1004.04 Modifications to a Proposed Facility or an
Existing DER.
(a)
At any time after an application is deemed complete, including after the
receipt of fast track, supplemental review, group study, SIS, or detailed study
results, the applicant or the utility may identify modifications to the proposed
facility. Existing DERs may also propose
modifications. The applicant for a
proposed facility or interconnecting customer, for an existing DER, shall
submit to the utility, in writing according to each utility’s processes, all
proposed modifications to the facility. The
utility shall not unilaterally apply any modification to an application
or facility.
(b)
Within 10 business days of receipt of a proposed modification, the utility
shall notify the applicant whether the proposed modification constitutes an exempt
modification, member impact modification, or material modification as outlined
below:
(1) If the proposed modification is determined by
the utility to be an exempt modification, then the utility shall notify the applicant
in writing that the modification has been accepted and that the applicant shall
retain its eligibility for interconnection, including its place in the queue;
(2) If the application proposed to be modified is
part of a group study, and the proposed modification is determined to be a member
impact modification, written approval shall be required from all other applicants
in the group and the utility as follows:
a. The applicant shall submit written approval
from all other applicants in the group within 10 business days of notification
from the utility that the modification is a member impact modification;
b. Within 20 business days of receipt of written
authorization from all other applicants in the group, the utility shall provide
the applicant with estimated costs, timelines, and requirements for revising
the group study process;
c. Within 10 business days of notification from
the utility related to estimated costs, timelines, and requirements for
revising the group study process, the applicant shall submit written approval
from all other applicants in the group and pay the utility pursuant to the term
of the group study agreement. If the applicant
does not provide such approval and payment, the proposed modification shall be
deemed withdrawn;
d. Within the timeline specified in (b)(2)b.
above in this section, the utility shall provide the applicant with a
description of the utility’s analysis, conclusions, and the reasoning
supporting those conclusions; and
e. Within 10 business days of receipt of the
results from the updated group study, the applicant shall notify the utility of
its election to proceed with the modification and provide written approval of
the modification from all other applicants in the group. If the applicant does not provide its written
approval, the proposed modification, shall be deemed withdrawn;
(3) If the proposed modification is determined to
be a material modification, the utility shall notify the applicant in writing
that the applicant shall provide the utility with its decision in writing by either
withdrawing the proposed modification, or by notifying the utility that it
wishes to proceed with the modification;
(4) The applicant shall provide its decision
within 10 business days after the material modification determination
notification, which shall note the due date for a response from the
applicant. If the applicant does not
provide its decision by the date provided in the notification, the proposed
modification shall be deemed withdrawn by the applicant, the application shall
remain unchanged and retain its queue position; and
(5) If the applicant notifies the utility that it
wishes to proceed with the modification within the timeframe indicated in (b)(4)
above in this section then the utility shall add the modification to the application
and place the application at the end of the queue.
(c)
Any change to the application or proposed facility not previously agreed
upon by both the applicant and the utility shall be prohibited and shall result
in the application being eligible for removal from the queue.
(d) Each utility shall
provide a process for interconnecting customers to propose changes to existing
DERs. Applications for modifications to existing
DERs, whether changes to the existing facility itself or the addition of an
energy storage device, shall follow this process. Proposed changes that are determined to be an exempt
modification shall not require processing through the queue.
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En 1004.05 Site Control. Documentation of site control shall be
submitted with the application. Site
control may be demonstrated by providing documentation of any of the following:
(a) Proof of ownership of, a leasehold interest
in, or a right to develop the applicant’s property for the purpose of
constructing a facility;
(b)
A copy of or proof of a fully executed option to purchase or acquire a
leasehold interest in the facility site for such purpose;
(c)
A copy of a fully executed agreement demonstrating exclusivity or other
business relationship between the applicant and the entity having the authority
to grant the applicant the right to possess or occupy the facility site for
such purpose; or
(d)
A Federal Energy Regulatory Commission (FERC) license
in good standing for hydroelectric generating facilities demonstrating that the
applicant has authority to act on behalf of the facility.
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En 1004.06 Continued Review. If an application
does not qualify for interconnection under one review path, but the applicant
decides to continue with review under another review path within 10 business
days of receipt of utility denial of elected review path, the applicant shall
retain its original queue position.
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En
1004.07 Standard Forms. Each utility shall submit templates or models
of its current IA, SISA, group study agreement, group study consent form, detailed
study agreement, and application to the department no more than once a year by
March 15.
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PART En 1005 APPLICABLE STANDARDS
En 1005.01 Applicable Standards. The applicant and DER shall comply with the utility’s
TIR as defined in En 1002.53 and the standards identified in this section, as
applicable, unless waived by the utility. If the utility’s published technical
interconnection standards specify a more recent industry standard, then the
industry standard cited in the utility’s technical interconnection standards
shall prevail. Applicable standards
include the following:
(a) IEEE
Std 1547-2018, “IEEE Standard for Interconnection and Interoperability of
Distributed Energy Resources with Associated Electric Power Systems Interfaces”
dated 4/6/2018 as available in Appendix B;
(b) IEEE
Std 1547.1™-2020, “IEEE
Standard Conformance Test Procedures for Equipment Interconnecting Distributed
Energy Resources with Electric Power Systems and Associated Interfaces” dated
5/21/20 as available in Appendix B;
(c) ANSI C84.1-2020,
“Electric Power Systems and Equipment-Voltage Ratings (60 Hertz)” dated
3/10/2020 as available in Appendix B;
(d) IEEE
Std 1547.2™-2023, “IEEE Application Guide for IEEE Std 1547™-2018, IEEE Standard for
Interconnection and Interoperability of Distributed Energy Resources with
Associated Electric Power Systems Interfaces” dated 5/20/2024 as
available in Appendix B;
(e) IEEE Std 1547.3™-2023, “IEEE
Guide for Cybersecurity of Distributed Energy Resources Interconnected with
Electric Power Systems” dated 12/11/2023 as available in Appendix
B;
(f) IEEE
Std 1547.7™-2013, “IEEE
Guide for Conducting Distribution Impact Studies for Distributed Resource
Interconnection” dated 2/28/2014 as available in Appendix
B;
(g) IEEE
Std 519™-2022, “IEEE
Standard for Harmonic Control in Electric Power Systems” dated 8/5/2022 as
available in Appendix B;
(h) IEEE
Std 1453™-2022, “IEEE
Standard for Measurement and Limits of Voltage Fluctuations and Associated
Light Flicker on AC Power Systems” dated 2/27/2023 as
available in Appendix B;
(i) IEEE
Std C37.90.2™-2024, “IEEE
Standard for Relays, Relay Systems, and Control Devices used for Protection and
Control of Electric Power Apparatus-Radiated Electromagnetic Interference
Withstand Capability Requirements and Tests” dated 1/31/2025 as
available in Appendix B;
(j)
IEEE C37.95™-2014, “IEEE Guide for Protective Relaying of
Utility-Consumer Interconnections” dated 5/5/2014 as available in Appendix B;
(k) IEEE
Std C50.13™-2014, “IEEE
Standard for Cylindrical-Rotor 50 Hz and 60 Hz Synchronous Generators Rated 10
MVA and Above” dated 5/9/2014 as available in Appendix B;
(l) IEEE
Std C62.92.1™-2016, “IEEE
Guide for the Application of Neutral Grounding in Electric Utility Systems-Part
I: Introduction” dated 3/31/2017 as available in Appendix
B;
(m) IEEE
Std C62.92.2™-2017, “IEEE
Guide for the Application of Neutral Grounding in Electric Utility Systems,
Part II-Synchronous Generator Systems” dated 5/19/2017 as
available in Appendix B;
(n) IEEE
Std C62.92.6™-2017, “IEEE
Guide for Application of Neutral Grounding in Electrical Utility Systems, Part
VI-Systems Supplied by Current-Regulated Sources” dated 12/22/2017 as
available in Appendix B;
(o) UL 1741, “Inverters,
Converters, Controllers and Interconnection System Equipment for Use With
Distributed Energy Resources” dated 4/22/2025 as available in Appendix
B;
(p) Certification
Requirement Decision for Power Control Systems, March 8, 2019, Inverters,
Converters, Controllers and Interconnection System Equipment for Use With
Distributed Energy Resources found in UL 1741, “Inverters, Converters,
Controllers and Interconnection System Equipment for Use With Distributed
Energy Resources” dated 4/22/2025 as available in Appendix
B;
and
(q) UL
3141 “UL LLC Outline of Investigation for Power Control Systems” dated 10/9/2024
as available in Appendix B.
Source. #14657,
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En 1005.02 Utility TIRs. Each utility shall publish and maintain TIRs.
The utilities shall convene a TIR
working group quarterly that includes participation from interested
stakeholders to ensure technical standards are regularly maintained, updated,
and consistent with good utility practice. The TIR working group shall be comprised of 6
members with 3 members representing utilities and 3 members representing
companies engaged in the development and installation of DERs in New Hampshire.
The TIR working group shall have 2
co-chairs with one representing utility members and one representing industry
members. The utilities shall provide
notice of changes to the TIR working group.
Source. #14657,
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En 1005.03 Index of technical standards. Each utility shall publish and maintain a
complete index of all technical standards and requirements pursuant to En 1000
with references to each of the standards and requirements in a place of
prominence and easy accessibility on each utility’s website.
Source. #14657,
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PART En 1006 PRE-APPLICATION REPORT
En 1006.01 Pre-Application Report Request. Applicants who
elect to submit a pre-application report to the utility as permitted by En
1003.01 shall include in their request the following information:
(a)
Contact
information to include name, address, phone number, and email address;
(b)
A proposed POI that includes the latitude and longitude, site map,
street address, utility equipment number, for example pole number, meter
number, account number, or some combination of the above sufficient to clearly
identify the location of the proposed POI;
(c)
Facility type, for example solar, wind, combined heat and power,
storage, or solar-plus-storage;
(d)
Nameplate rating and export capacity, if different;
(e)
Single- or 3-phase configuration;
(f)
Whether the facility is stand-alone or will service onsite load;
(g)
Whether new service is requested; and
(h) Non-refundable processing fee to the utility as
approved by the commission.
Source. #14657,
eff 9-1-26, EXPIRES: 9-1-36
En 1006.02 Pre-Application Report.
(a)
Within 10 business days of receipt of a completed pre-application report
request, the utility shall provide a pre-application report to the applicant. The pre-application report shall include the
following information, if available:
(1) Circuit voltage at the substation;
(2) Circuit name;
(3) Circuit voltage at the proposed facility;
(4) Substation name;
(5) Substation transformer rating;
(6) Whether or not 3-phase power is available at
the site or distance from 3-phase service;
(7) Aggregate existing export capacity (MW)
interconnected to the substation, area bus, transformer bank, and distribution circuit
expected to serve proposed site;
(8) Aggregate queued export capacity (MW)
proposing to interconnect to the substation, area bus, transformer bank, and distribution
circuit expected to serve proposed site;
(9) Whether zero sequence voltage (3V0) protection
is deployed or scheduled for deployment on the circuit or substation;
(10) Whether the proposed facility is located on
an area, spot, or radial network;
(11) Identification of feeders within 1/4 mile of
the proposed interconnection site through a snapshot of geographic information
system (GIS) map or other means;
(12) For the nearest available feeder, the circuit
rating and approximate circuit length from the proposed facility to the
substation;
(13) Whether an ASO has informed the utility that
an ASO study is required, or the utility is aware of an ongoing ASO study for
the proposed facility interconnection location;
(14) Total capacity (MW) of substation, area bus, transformer
bank, and distribution circuit expected to serve proposed site, based on the
thermal ratings of the utility’s electric delivery system;
(15) Available capacity (MW) of substation, area
bus, transformer bank, and distribution circuit expected to serve proposed
site, based on the thermal ratings of the utility’s EDS. Available capacity is the total capacity less
the sum of existing and queued export capacity, accounting for all load served
by existing and queued facilities;
(16) Relevant line section(s) and substation
actual or estimated peak load and minimum load data;
(17) Number and rating of protective devices and
number and type of voltage regulating devices between the proposed site and the
substation or area bus;
(18) Limiting conductor rating from proposed POI
to distribution substation;
(19) Based on proposed POI, existing or known
constraints such as, but not limited to, electrical dependencies at that
location, short circuit interrupting capacity issues, power quality or
stability issues on the circuit, capacity constraints, or secondary networks;
and
(20) Any other information the utility deems
relevant to the applicant.
(b)
The pre-application report shall include language to inform the
applicant that:
(1) The existence of available capacity in no way
implies that an interconnection up to this level may be completed without
impacts because there are many variables studied as part of the interconnection
review process;
(2) The utility EDS is dynamic and subject to
change; and
(3) Data provided in the pre-application report might
become outdated and not useful at the time of submission of the complete
application.
(c)
The pre-application report shall only include pre-existing data. A pre-application report request shall not
obligate the utility to conduct a study or other analysis of the proposed
project if data is not available. If the
utility cannot complete all or some of a pre-application report due to lack of
available data, the utility shall provide the potential applicant with a pre-application
report that includes the information that is available and identify the
information that is unavailable.
(d)
Notwithstanding any of the provisions of this section, the utility shall
provide pre-application report data that represents the best available
information at the time of submission.
Source. #14657,
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PART En 1007 SIMPLIFIED PROCESS REVIEW
En 1007.01 Eligibility. Simplified process review shall be available
to any certified inverter-based facility that has a nameplate rating that does
not exceed 50 kW and has an export capacity of 25 kW or less. If the facility’s export capacity is not
limited, the nameplate rating shall not exceed 25 kW.
Source. #14657,
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En 1007.02 Application. An applicant shall submit an application with
the fee pursuant to En 1004.01, which shall be sent electronically pursuant to
each utility’s instructions.
Source. #14657,
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En 1007.03 Simplified Process Screen. The utility shall evaluate the application to
ensure the equipment is certified to current standards and the utility’s EDS is
able to accommodate the facility. The utility
shall utilize the following screens as applicable to each facility review:
(a)
For certified equipment screens, the applicant-facility shall utilize
an inverter certified to Supplement SB as found in UL 1741, “Standard for
Inverters, Converters, Controllers with Interconnection System Equipment for
Use with Distributed Energy Resources” dated 4/22/2025 as available in Appendix
B;
(b)
For minimum load screen for interconnection of a facility to a radial
distribution circuit, the facility’s export capacity, aggregated with the export
capacity of all other existing DERs on a line section, shall not exceed 100
percent of the line section’s relevant minimum load as most recently measured
at the substation or calculated for the line section. If the utility does not have relevant minimum
load data, 25 percent of the peak feeder load shall be used instead;
(c)
For shared secondary screens, if the facility is to be interconnected on
a single-phase shared secondary, then the aggregate generation capacity on the
shared secondary, including the facility’s export capacity, shall not exceed 25
kVA;
(d)
For service imbalance screens, if the facility is single-phase and is to
be interconnected on a transformer center tap neutral of a 240-volt service,
its addition shall not create an imbalance between the 2 sides of the 240-volt
service of more than 20 percent of the nameplate rating of the service
transformer; and
(e)
For network screens for interconnection of a facility within a spot
network or area network, the export capacity shall be 15 kW or less, and the
aggregate nameplate rating including the facility’s nameplate rating shall not
exceed one fifteenth of the spot network or area network’s relevant minimum
load. Alternately, if the utility does
not have minimum load data for the spot or area network, the utility shall
select any of the following methods to determine anticipated minimum load:
(1) Five percent of the spot network or area
network’s maximum load in the previous year;
(2) The utility’s estimate, if provided in
writing to the applicant along with an explanation why the utility cannot
calculate or measure minimum load; or
(3) If there is no existing meter or the existing
metering in place cannot be used to determine the minimum load, then a meter
capable of recording minimum loads shall be installed at the applicant’s
expense as follows:
a. In such cases, the utility shall install an
appropriate meter to measure 3 months of continuous customer load capturing the
annual minimum load. The maximum time
the utility-approved monitoring equipment shall be used to measure the minimum
load is 9 months from the point of the time the analysis was commenced; and
b. The utility shall remove the meter at the applicant’s
expense if the applicant requests its removal provided the interval meter is
not required to bill the rate on which the customer shall take service when the
facility is interconnected.
Source. #14657,
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En 1007.04 Time to Process Screens. Within 15 business days after the utility
notifies the applicant that the application is complete, the utility shall
notify the applicant whether the facility meets all the applicable simplified
process screens. If the applicant is
proposing to interconnect within a spot network or area network and an interval
meter is required pursuant to En 1007.03(e)(3), the utility shall notify the applicant
whether the facility meets all the applicable simplified process screens within
60 business days after the utility notifies the applicant that the application
is complete.
Source. #14657,
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En 1007.05 Screens Failure.
(a)
Despite the failure of one or more screens, the utility may authorize an
applicant or facility to interconnect to the EDS provided such interconnection
does not compromise the safe and reliable operation of the EDS.
(b)
If the utility determines that the facility cannot interconnect based on
screen results, the utility shall provide the applicant with the screen results
detailing the specific screens that the application failed, including the
technical reason for failure. The screen
results shall include information about the specific system threshold or
limitation causing the application to fail the screen, and the utility shall
discuss the applicant’s options to interconnect based on current circumstances.
Upon review of the screen results, the utility
shall allow the applicant to undergo supplemental review, in accordance with En
1009. The applicant shall notify the utility
of its selection to proceed to further study within 10 business days or the application
shall be deemed withdrawn.
Source. #14657,
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En 1007.06 Approval.
(a)
If the application passes the screens, the application shall be
approved, and the utility shall provide the applicant with a written notice of
approval to install within 15 business days of deeming the application
complete.
(b)
If the facility requires no system modifications to the EDS, the utility
shall provide the applicant with PTO following receipt of certificate of
completion and closing paperwork pursuant to En 1004.
(c)
If the facility requires any EDS modifications, the utility shall provide
written conditional approval to interconnect, along with an itemized, non-binding good faith cost estimate and construction
schedule for such upgrades, to the applicant within 15 business days of
providing the screening results.
Source. #14657,
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En 1007.07 Time for Commencing Operation. Unless extended by mutual agreement of the parties,
within 12 months of fully executing the IA or 12 months from the completion of
any necessary EDS modifications, whichever is later, the applicant shall
commence operation of the facility subject to satisfying En 1007.08 and En 1007.09. The applicant shall provide the utility with notice
of the completion of construction of the facility.
Source. #14657,
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En 1007.08 Final Utility Review and Metering.
(a)
If the utility determines that a review of the facility or changes to
the applicant’s meter are necessary, the utility shall complete this work
within 10 business days of receiving the complete facility as-built
documentation from the applicant. If the
facility passes the review, the utility shall provide written notice of the
passage within 3 business days.
(b)
If the facility initially fails a utility review, the utility shall
offer to reinspect the facility at the applicant’s expense at a time mutually
agreeable to both the utility and the applicant. If the utility determines that the facility
fails the review, including the discovery of unapproved changes to the facility,
the utility shall provide the applicant with a written explanation detailing
the reasons for the failure and any standards violated within 3 business days.
(c) If the utility determines no inspection or
changes to the applicant’s meter are necessary, it shall notify the applicant
within 3 business days of receiving the notice of the completion of
construction.
Source. #14657,
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En 1007.09 Operation. The utility shall provide PTO and the facility
may begin operating provided that:
(a) The applicant has received conditional
approval to interconnect;
(b)
The utility has received proof of the respective electric code
official’s approval including a signed certificate of completion or other
inspector-code official provided documentation;
(c)
The applicant successfully completed the witness test if required by the
utility pursuant to En 1011.11; and
(d) The applicant has received written notice that
the facility passed any review required by the utility or received notice that no
review is required.
Source. #14657,
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PART En 1008 FAST TRACK PROCESS REVIEW
En 1008.01 Eligibility. Fast track review shall be available to any facility
that has an export capacity that does not exceed 1 MW.
Source. #14657,
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En 1008.02 Application. An applicant shall submit a complete application
with the fee pursuant to En 1004.01, which shall be sent electronically pursuant
to each utility’s instructions. Separate
from and in addition to the application fee described in En 1004.01, the
applicant shall submit a fee for fast track review. The fast track review fee shall be utility
specific and designed to recover all costs associated with the fast track
review process, shall be based upon the applicant’s facility export capacity,
and may consist of a fixed fee in whole or in part.
Source. #14657,
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En 1008.03 Required Screens. The utility shall evaluate the application
using the following screens:
(a) For minimum load screen for interconnection of
a DER to a radial distribution circuit, the DER’s export capacity, aggregated
with the export capacity of all other DERs on a line section, shall not exceed
100 percent of the line section’s relevant minimum load as most recently
measured at the substation or calculated for the line section. If the utility does not have relevant minimum load
data, 25 percent of the peak feeder load shall be used instead;
(b)
For inadvertent export screen for interconnection of a proposed DER that
can introduce inadvertent export, where the nameplate rating of the DER minus
the export capacity is greater than 250 kW, the power change equal to the nameplate
rating minus the export capacity, the change in voltage at the point on the
medium voltage (primary) level nearest the POI shall not exceed 3 percent. Voltage change will be estimated applying the
following formula:
|
Formula |
(RSOURCE × ∆𝑷) – (XSOURCE × ∆𝑸) V2 |
|
Where: ∆𝑷 = (DER
apparent power Nameplate Rating – Export Capacity) × PF, ∆𝑸 = (DER
apparent power Nameplate Rating – Export Capacity) × RSOURCE is the grid resistance, XSOURCE
is the grid reactance, V is the grid voltage, PF is the power factor |
|
(c) For fault current contribution screen, the
DER, aggregated with other generation on the distribution circuit, shall not
contribute more than 10 percent to the distribution circuit’s maximum fault current
at the point on the primary nearest the proposed POI;
(d) For short circuit interrupting capability
screen, the DER, aggregated with other generation on the distribution circuit, shall
not cause any distribution protective devices and equipment, including but not
limited to substation breakers, fuse cutouts, and line reclosers, or utility
customer equipment on the system, to exceed 90 percent of the short circuit
interrupting capability, nor is the interconnection proposed for a circuit that
already exceeds 90 percent of the short circuit interrupting capability;
(e) The line configuration screen shall include a
review of the type of electrical service provided to the interconnecting
customer, including line configuration and the transformer connection to limit
the potential for creating over-voltages on the utility’s EDS due to a loss of ground
during the operating time of any anti-islanding function. The DER shall comply with the applicable type
of interconnection, based on Table 1008 below:
Table 1008: Line
Configuration for DER Interconnection
|
Primary
Distribution Line Configuration |
Type
of Interconnection to Primary Distribution Line |
Results/Criteria |
|
3-phase,
3-wire |
3-phase
or single-phase, phase-to-phase |
Pass
Screen |
|
3-phase,
4-wire |
3-phase
or single-phase, line-to-neutral |
Pass
Screen |
(f)
For
shared secondary transformer screens, if the facility is to be interconnected
on a single-phase shared secondary, then the aggregate export capacity on the
shared secondary, including the facility’s export capacity, shall not exceed 25
kVA. The utility shall consider voltage
control capabilities of the facility to determine if such controls can
alleviate the voltage concern identified by this screen;
(g) For service imbalance screens, if the DER is
single-phase and is to be interconnected on a transformer center tap neutral of
a 240-volt service, its addition shall not create an imbalance between the 2
sides of the 240-volt service of more than 20 percent of nameplate rating of
the service transformer;
(h) For transient stability screens, the DER’s nameplate
rating, in aggregate with other generation interconnected to the distribution
low-voltage side of the substation transformer feeding the distribution circuit
where the DER proposes to interconnect shall not:
(1) Exceed 10 MW in an area where there are known
or posted transient stability limitations to generating units located in the
general electrical vicinity for example 3 or 4 transmission voltage level
busses from the POI; and
(2) Have interdependencies, known to the utility,
with earlier queued interconnection requests, that would necessitate further
study;
(i) For stiffness screens, the ratio of the utility
short circuit current at the PCC to the proposed DER’s nameplate rated current
shall not be less than 25;
(j) For transmission screens, the DER’s PCC shall
not be on a transmission line;
(k) For network screens for interconnection of a
DER within a spot network or area network, the aggregate nameplate rating
including the DER’s nameplate rating shall not exceed 50 percent of the spot
network or area network’s relevant minimum load. Alternately, if the utility does not have
minimum load data for the spot or area network, the utility may select any of
the following methods to determine anticipated minimum load:
(1) Five percent of the spot network or area network’s
maximum load in the previous year;
(2) The applicant’s good faith estimate, if
provided; or
(3) The utility’s estimate if provided in writing
to the applicant along with the reasons why the utility considered the other
methods to estimate minimum load inadequate; and
(l)
For effective grounding screens, the proposed facility in
aggregation with other generation in the vicinity of the proposed POI shall not
exceed the utility’s threshold for requiring effective grounding established in
the utility’s current TIR.
Source. #14657,
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En 1008.04 Time to Process Screens. Within 25 business days after the utility
notifies the applicant that the application is complete, the utility shall
notify the applicant whether the facility meets all of the applicable fast
track screens. The utility’s 25 business day notification shall not
include time when the application is on hold pending information to be provided
by the applicant or other hold requested by the applicant and approved by the
utility.
Source. #14657,
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En 1008.05 Screens Failure. Despite the failure of one or more screens,
the utility, at its sole discretion, shall approve the interconnection provided
such approval is consistent with safety and reliability. The utility shall provide the applicant with
the screen results in the event of failure of any screens identifying which of the
specific screens the application failed, the technical reason for failure, and
the specific system threshold or limitation causing the application to fail the
screen. The utility shall provide the applicant
with the option to either undergo supplemental review, in accordance with En 1009,
or proceed under the standard process beginning with the SIS pursuant to En
1011.06. Upon receipt of the screening
results, the applicant shall notify the utility of its selection within 10 business
days or the application shall be deemed withdrawn.
Source. #14657,
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En 1008.06 Approval. If the applicant passes the screens, the
application shall be approved, and the utility shall provide the applicant with
an executable IA within the following timeframes:
(a)
If the facility requires no EDS
modifications by the utility, the utility shall provide the IA to the applicant
at the same time that the utility provides the fast track or supplemental
review results; or
(b)
If the facility requires EDS modifications, the utility shall provide
the IA, along with an itemized, non-binding cost estimate and construction
schedule for such upgrades, to the applicant within 15 business days after the
fast track or supplemental review results.
If the cost to generate the non-binding estimate exceeds $2,500, the
utility shall invoice the applicant for the cost of the estimate. The applicant shall remit payment to proceed
within 10 business days of receipt of the invoice or the application shall be
deemed withdrawn.
Source. #14657,
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En 1008.07 Reference Point of Applicability Review.
This process shall occur concurrently
with fast track screening pursuant to En 1008.04:
(a) If it is determined that the RPA is
appropriate, the utility shall notify the applicant when it provides the screen
results and proceed according to En 1008.04; and
(b) If the utility determines that the RPA is
inappropriate, the following shall occur:
(1) The utility shall notify the applicant and
with the notification include an explanation as to why it requires correction;
(2) Upon receipt of notification from the utility
the applicant shall provide the utility with a corrected application with the
proper RPA within 5 business days of notification;
(3) The utility shall review the corrected
application with the proper RPA within 5 business days of receipt;
(4) If the proper RPA is provided, the utility
will proceed according to En 1008.04; and
(5) If the applicant does not provide the
appropriate location or request an extension of time within the deadline, the
application shall be deemed withdrawn.
Source. #14657,
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En 1008.08 IA Execution.
(a)
An applicant that receives an IA shall have 15 business days to execute
the agreement and return it to the utility along with any required payment due
upon execution of the IA.
(b) Failure to submit an executed IA with the
necessary payment shall result in withdrawal of the application from the queue
upon the utility notifying the applicant unless the applicant and the utility
mutually agree to extend the deadline pursuant to En 1014.02.
(c)
Within 24 months from an applicant’s execution of an IA or 6 months of
completion of any EDS modifications, whichever is later, the facility shall
commence operation unless the applicant and utility agree to an extension. The applicant shall provide the utility with
notice of the completion of construction of the facility.
Source. #14657,
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En 1008.09 Final Utility Review and Metering. If the utility determines that a review of
the facility or changes to the applicant’s meter are necessary, the following
shall occur:
(a)
The utility shall review the facility or change the applicant’s meter within
10 business days of receiving the complete facility as-built documentation from
the applicant;
(b)
If the facility passes the review, the utility shall provide written
notice of such outcome to the applicant within 3 business days;
(c)
If the facility initially fails a utility review, the utility shall
offer to conduct the inspection again at the applicant’s expense at a time
mutually agreeable to both the utility and the applicant;
(d)
If the utility determines that the facility fails the review described
in (c) above in this section, including the discovery of unapproved changes to
the facility, the utility shall provide the applicant with a written
explanation detailing the reasons for the failure and any standards violated
within 3 business days; and
(e)
If the utility determines no review or changes to the applicant’s meter
are necessary based on its review described in (a) above in this section, it
shall notify the applicant within 3 business days of receiving the notice of
the completion of construction.
Source. #14657,
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En 1008.10
Operation. An applicant
may begin operating if:
(a)
There is an IA in effect;
(b)
The utility has received proof of the respective electric code
official’s approval including a signed certificate of competition or other
inspector-code official provided documentation;
(c)
The applicant successfully completed the witness test if required by the
utility pursuant to En 1011.11; and
(d)
The applicant has received written notice that the facility passed any
review required by the utility or received notice that no review is required.
Source. #14657,
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PART En 1009 SUPPLEMENTAL REVIEW
En 1009.01 Supplemental Review. If the applicant agrees to undergo
supplemental review, it shall notify the utility and submit a fee for
supplemental review in accordance with the timeline specified in En 1007.05 or
En 1008.05. The supplemental review fee shall
be utility specific and designed to recover all costs associated with the supplemental
review process, shall be based upon the applicant’s facility export capacity,
and may consist of a fixed fee in whole or in part.
Source. #14657,
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En 1009.02 Utility Response to Supplemental Review.
Within 20 business days of an applicant’s
election to undergo supplemental review and payment of the fee, the utility
shall perform supplemental review using the screens set forth below in En
1009.03, notify the applicant of the results, and include with the notification
a written report of the analysis and data underlying the utility’s
determinations under the screens, including information about the specific
system threshold or limitation causing the result.
Source. #14657,
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En 1009.03 Screens. The utility shall evaluate the application using
the following screens as applicable:
(a) The utility shall apply the minimum load screen
analysis as follows:
(1) Where 12 months of line section minimum load
data, including onsite load but not station service load served by the proposed
facility, are available, can be calculated, estimated from existing data, or
determined from a power flow model, the facility’s export capacity aggregated
with all other generation capable of exporting energy on the line section is
less than 100 percent of the relevant minimum load for all line sections
bounded by automatic sectionalizing devices upstream of the proposed facility;
(2)
If the minimum load data is not
available, or cannot be calculated or estimated, the facility’s export capacity
aggregated with all other generation capable of exporting energy on the line section
is less than 30 percent of the peak load for all line sections bounded by
automatic sectionalizing devices upstream of the proposed facility;
(3) Load that is co-located with load-following,
non-exporting, or export-limited generation shall be appropriately accounted
for; and
(4) The utility shall not consider as part of the
aggregate export capacity for purposes of this screen facility export capacity,
including combined heat and power (CHP) facility capacity, known to be already
reflected in the minimum load data;
(b) The utility shall apply the voltage and power quality
screen. In instances where the facility
limits export pursuant to En 1013, the export capacity instead of nameplate rating
shall be utilized including power flow simulations. When combined with existing generation on the
same line section, the aggregate impact shall be evaluated to ensure compliance
with voltage and power quality standards:
(1)
The voltage regulation on the line section
shall be maintained in compliance with relevant requirements under all system
conditions;
(2)
The voltage fluctuation shall be within
acceptable limits as defined by IEEE Std 1547™-2018,
“IEEE Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018
as available in Appendix B; and
(3)
The harmonic levels shall comply with limits
at the RPA pursuant to the IEEE Std 1547™-2018,
“IEEE Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018,
as available in Appendix B;
(c)
The utility shall apply the supplemental grounding screen if the facility
failed the effective grounding screen pursuant to En 1008.03(l). The supplemental grounding screen shall be
applied as follows:
(1) For facilities with a rotating machine,
effective grounding shall be maintained; or
(2)
For facilities with a three-phase
inverter, the utility shall apply the following criteria to evaluate whether
the DER is effectively grounded:
a. The line-to-neutral
connected load on the feeder or line section is greater than 33 percent of peak
load on the feeder or line section;
b. If using a supplemental grounding software
tool:
i. The tool determines that supplemental
grounding is not required to maintain effective grounding;
ii. If the
tool determines that supplemental grounding is required, the applicant shall
agree to modify the facility to include supplemental grounding; and
c.
If using a detailed hosting capacity
analysis that incorporates evaluation of temporary overvoltage risk for
inverters, the nameplate rating of the facility is below the available hosting
capacity at the POI;
(d)
The utility shall apply the safety and reliability screen. The location of the proposed facility and the
aggregate export capacity on the line section shall not create impacts to
safety or reliability that cannot be adequately addressed without standard process
review. If the facility limits export
pursuant to En 1013, the export capacity shall be included in any analysis
including power flow simulations, except when assessing fault current
contribution. To assess fault current
contribution, the rated fault current shall be used; and
(e) When making a determination concerning the
impacts to safety and reliability in applying the screen in (d) above in this
section, the utility shall consider the following factors which shall include
but not be limited to:
(1) Whether the line section has significant
minimum loading levels dominated by a small number of customers, for example
several large commercial customers;
(2) Whether there is an even or uneven
distribution of loading along the feeder;
(3) Whether the proposed facility is located in
close proximity to the substation, for example < 2.5 electrical circuit
miles, and whether the distribution line from the substation to the POI is
composed of large conductor or feeder section, for example 600A class cable;
(4) Whether the proposed facility incorporates a
time delay function to prevent reconnection of the facility to the system until
system voltage and frequency are within normal limits for a prescribed time;
(5) Whether operational flexibility is reduced by
the proposed facility, such that transfer of the line section(s) of the facility
to a neighboring distribution circuit or substation might trigger overloads or
voltage issues; and
(6) Whether the proposed DER utilizes certified anti-islanding
functions and equipment.
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En 1009.04 Passage of the Supplemental Screens. If the proposed interconnection passes the
supplemental screens, the utility shall approve the application and provide the
applicant an executable IA pursuant to the procedure set forth in En 1008.06. After receiving an IA executed by the utility,
the applicant shall proceed under the terms of the applicable level of review
under which the application was initially studied.
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PART En 1010 APPLICANT OPTIONS MEETING
En 1010.01 Applicant Options Meeting.
(a)
If the utility determines that an application that has gone through the simplified
process, the fast track process, or supplemental review requires review using
the standard process, the utility shall provide the applicant the option of
proceeding to standard process review or of participating in an applicant options
meeting with the utility to review the screening analysis and related results
and possible application modifications to determine what further study is
needed for the facility to proceed with interconnection to the EDS.
(b)
The applicant shall request either an applicant options meeting or notify
the utility that it shall proceed with the standard process within 10 business
days of receipt of screen results or the application shall be deemed withdrawn. If the applicant requests an applicant options
meeting, the utility shall offer to convene the meeting at a mutually agreeable
time within 15 business days of the applicant’s request.
(c)
After the applicant options meeting, the applicant may choose within 10
business days to either amend the application or proceed with the standard
process pursuant to the following process:
(1)
If the applicant chooses to amend the application
to address the specific failed screens, the applicant shall have one
opportunity to submit an updated application including all necessary redesigns
that address screen failures within 10 business days;
(2) If the applicant makes any material modifications
that do not directly correct the screen failure(s), it shall result in the application
losing its queue position and being placed at the end of the queue; or
(3) If the applicant fails to either amend the
application or proceed with the standard process within 10 business days of
receiving the notification from the utility of the results of the evaluation described
in (d) below in this section, the application shall be deemed withdrawn.
(d)
Within 20 business days of receiving the updated application, the
utility shall evaluate whether the redesign addresses the screen failure(s) and
notify the applicant of the results of this evaluation.
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PART En 1011 STANDARD PROCESS
En 1011.01 Application. An applicant shall submit an application with
the fee pursuant to En 1004.01 electronically in compliance with the utility’s
instructions.
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En 1011.02 System Impact Study Agreement. Separate from and in addition to the
application fee pursuant to En 1004.01, all expected costs necessary for the
utility to conduct necessary EDS study shall be set forth in a separate SISA
between the utility and the applicant, issued by the utility, the payment of
which shall be due in full prior to the commencement of work. The utility shall make their best faith
efforts to estimate the actual costs necessary to study the EDS for
interconnection of the applicant’s proposed facility. As set forth in the SISA, the applicant shall
bear and be responsible for all costs to interconnect the facility to the
system, including, without limitation, all necessary system modification
costs. Should any dollars remain from
the SISA, they shall be included in the true up as a part of the final
accounting described in En 1018.11.
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En 1011.03 Scoping Meeting.
(a)
The utility shall conduct an initial review that includes a scoping
meeting with the applicant within 15 business days of determining that an application
is complete. The purpose of the scoping
meeting shall be to discuss the application, the RPA, and review existing
studies relevant to the application.
(b)
The scoping meeting shall take place in person, by telephone, or
electronically by a means mutually agreeable to the utility and applicant.
(c)
At the scoping meeting, the utility shall provide pertinent information
such as:
(1) The available fault current at the proposed
location;
(2) The existing peak loading on the lines in the
general vicinity of the proposed facility; and
(3) The configuration of the distribution line at
the proposed POI, and whether the proposed facility may be required to
participate in an ASO study.
(d)
The utility and the applicant shall bring to the meeting personnel,
including system engineers, and other resources as might be reasonably required
to accomplish the purpose of the meeting.
(e)
By mutual agreement of the parties, the scoping meeting, SIS, or detailed
study may be waived.
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En 1011.04 Affected System Operator.
(a)
The utility shall coordinate with the applicant, ASO, and any affected
system owners if an ASO study is required.
(b)
The utility shall not be responsible for the timing of an ASO study.
(c)
Within 10 business days following receipt of complete information from
the ASO, the utility shall provide the applicant with information related to
the plan for conducting the ASO study, including the responsibilities of each
party, the scope of the study, the expected timeline for completion, and the
estimated cost.
(d)
The applicant shall be directly responsible to the ASO and affected
system owner for all costs of any additional studies required to evaluate the
impact of the interconnection on the affected systems.
(e)
The applicant shall be directly responsible for any resulting affected
system costs, including, without limitation, modifications to the electric
power system of the ASO or affected system owner and operation and maintenance
costs.
(f)
The utility may, in its sole discretion, elect to include the additional
ASO study costs and affected system costs in the utility’s cost estimates. If the utility elects to include these costs
in its estimates, the utility shall specify the ASO study costs and the affected
system costs in its estimates. The applicant
shall pay the utility for those costs, and the utility shall pay those costs to
the ASO and affected system owner.
(g)
The applicant shall be responsible for all actual affected system costs
necessitated as a result of the ASO requirements, none of which shall be
subject to any cost caps or limitations under this chapter.
(h) Within 5 business days of notice from the ASO
that additional information or technical data about the facility is required
for the ASO study, the utility shall notify the applicant. The applicant shall provide the requested
information to the utility or request additional time from the utility within 15
business days of the notification from the utility. If the applicant fails to provide the
requested information within the allowed time, the applicant shall have the
opportunity to cure the failure ahead of the application being removed from its
queue position pursuant to the required notification period established in
1014.02(c). If the applicant does not
cure the failure within the required notification period, the application shall
be withdrawn unless the applicant and the utility mutually agree to extend the
deadline.
(i) Within 5 business days of notice from the ASO
of any ASO study costs, the utility shall notify the applicant. The applicant shall provide payment within 15
business days of the notification from the utility. If the applicant fails to provide payment
within the allowed time, the applicant shall have the opportunity to cure the
failure ahead of the application being removed from its queue position pursuant
to the required notification period established in 1014.02(c). If the applicant does not cure the failure
within the required notification period, the application shall be withdrawn
unless the applicant and the utility mutually agree to extend the deadline.
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En 1011.05 Group Study Process.
(a)
The utility may evaluate the application in a group study if any of the
following criteria are met:
(1) Interconnection of the facility will require
upgrading the substation transformer;
(2) Interconnection of the facility requires common
system modifications; or
(3) The applicant requests a group study and the utility
approves the request.
(b)
The utility shall not delay or deny a request for a group study based
solely on the requirement that a group member application participate in an ASO
study.
(c)
If an ASO study is required, the applicant may elect to proceed with the
group study pursuant to En 1012. If the applicant
elects to proceed with the group study prior to the completion of the ASO study
and the results of the ASO study require the utility to amend the applicant’s group
study, the utility shall provide an amended group study agreement with a cost
estimate and expected timeline to complete the updated group study.
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En 1011.06 System Impact Study.
(a)
If an ASO study is required, the applicant may elect to proceed with the
SIS pursuant to this section. If the applicant
elects to proceed with the SIS prior to the completion of the ASO study, and
the ASO study results necessitate revisions to the SIS, the utility shall issue
an amended SISA incorporating updated cost estimates and a revised schedule for
the completion of the amended SIS. The utility
shall complete the amended SIS in accordance with (g) below in this section.
(b)
For applicants participating in a group study, the group study shall
satisfy the requirement for a SIS. A separate
SIS shall not be required.
(c)
If the parties do not waive the SIS, within 10 business days of the
completion of the scoping meeting, or 10 business days after completion of the application
or the final step in the simplified process or fast track process if scoping
meeting is waived, the utility shall provide the applicant with a standard form
SISA, including a good faith estimate of the cost and time to undertake the SIS. The applicant shall return the signed SISA
within 20 business days, or the application shall be deemed withdrawn.
(d)
A SIS for a facility shall include a review of the facility’s adherence
to IEEE Std 1547™-2018, “IEEE Standard for Interconnection and
Interoperability of Distributed Energy Resources with Associated Electric Power
Systems Interfaces” dated 4/6/2018 as available in Appendix B. For facility components that are certified,
the utility shall not charge the applicant for review of those components in
isolation.
(e)
Each utility shall include in its SISA a description of the various
elements of a SIS it shall undertake pursuant to this section, which may
include but is not limited to:
(1) Load-flow study;
(3) Circuit protection and coordination study;
(4) Impact on system operation;
(5) Stability study and the conditions that would
justify including this element in the SIS; and
(6) Voltage-collapse study and the conditions
that would justify including this element in the SIS.
(f)
The SIS shall consider the proposed facility’s design and operating
characteristics and study the facility according to how the facility is
proposed to be operated. If the facility
limits export or import pursuant to En 1013, the SIS shall use export capacity
or import capacity instead of nameplate rating, except when assessing fault
current contribution.
(g)
The utility shall commence the SIS once an applicant submits an executed
SISA and required payment for the SIS. The
SIS shall be completed within 55 business days of the applicant’s submission of
the SISA and payment, unless the applicant and utility mutually agree to a
different completion term. The utility
shall true up all SISA payments to reflect final, actual costs of the SIS once
those costs are known. The utility shall
provide an SIS report that includes a description of the utility’s analysis,
conclusions, and the reasoning supporting those conclusions.
(h)
After the results of the SIS are delivered, if an applicant requests a
meeting to discuss results within 10 business days, the utility shall conduct a
results meeting with the applicant within 15 business days of providing the
results to the applicant. The results meeting
shall take place in person, by telephone, or virtually. The utility and the applicant shall bring to
the results meeting personnel, including system engineers, and other resources
as might be reasonably required to accomplish the purpose of the meeting.
(i)
Within 10 business days after the results meeting or the applicant’s
decision to waive the results meeting, the applicant shall notify the utility
of its decision to proceed with the IA, if applicable, request a modification
permitted pursuant to En 1004.04, or withdraw the application. Failure of the applicant to notify the utility
of its decision or request a modification shall result in the withdrawal of the
application.
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(a) If the utility determines that necessary
modifications to the utility’s EDS are substantial, the SIS report shall
include a high-level estimate of the system modification costs and an estimate
of the cost of an optional detailed study.
The optional detailed study shall provide granular costs of any EDS
modifications necessary to interconnect the applicant’s proposed facility.
(b)
If the applicant elects to participate in a group study pursuant to En
1012, the utility shall waive the detailed study.
(c)
If the utility determines that EDS modifications required to accommodate
the facility are not substantial, the SIS shall identify the scope and cost of
the EDS modifications defined in the SIS results, and no detailed study shall
be required.
(d)
If the applicant elects to proceed with the detailed study, within 10 business
days of the issuance of the SIS report, the utility shall provide a detailed
study agreement, including a good faith estimate of the cost and time to complete
the detailed study.
(e)
The utility shall execute the detailed study once the applicant completes
the detailed study agreement and submits payment. The detailed study shall include a granular
list of necessary EDS modifications, estimated milestones for completion of
modifications, and a non-binding, itemized cost estimate detailing equipment,
labor, operation and maintenance, contingencies, and other costs.
(f)
The utility shall complete the detailed study within 30 business days of
execution of the detailed study agreement and receipt of study payment if no
substation upgrades are required. If
substation upgrades are required, the timeline for detailed study shall be
established by mutual agreement.
(g)
After the results of the detailed study are delivered, if an applicant
requests a meeting to discuss the results within 10 business days, the utility shall
conduct a results meeting with the applicant within 15 business days of
providing the results to the applicant. The
results meeting shall take place in person, by telephone, or virtually. The utility and the applicant shall bring to
the results meeting personnel, including system engineers, and other resources
as might be reasonably required to accomplish the purpose of the meeting.
(h)
Within 10 business days after the results meeting or the applicant’s
decision to waive the results meeting, the applicant shall notify the utility
of its decision to proceed with the IA, if applicable, or request a
modification pursuant to En 1004.04, or
withdraw the application. Failure of the
applicant to notify the utility of its decision or request a modification shall
result in the withdrawal of the application.
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En 1011.08 Interconnection Agreement
(a) Within 15 business days of completion of the
last study or the meeting to discuss study results, whichever is later, the utility
shall provide the applicant with a signed IA using the current standard agreement, which shall incorporate
the milestones for completing EDS modifications, if any, from the detailed
study. The IA shall include a good
faith, non-binding estimate of all costs associated with interconnection of the
applicant’s proposed facility to the utility EDS including an itemized quote
including contingencies.
(b)
Within 15 business days of the receipt of the IA, the applicant shall either
execute or provide comments on the IA and return it to the utility. The utility shall have 15 business days to
respond to any applicant IA comments.
Upon the applicant’s receipt of the utility’s responses, the applicant
and utility shall attempt to resolve any issues identified by the applicant. The applicant shall either execute the IA
within 15 business days of the receipt of comments by the utility, or the applicant
may initiate informal dispute resolution efforts pursuant to En 1016, or
withdraw its IA at any time.
(c)
Payment of 25 percent of the utility’s good faith, non-binding estimate shall
be due within 45 business days of applicant signature of the IA with the
remaining 75 percent due within 90 business days of applicant signature of the
IA. Nothing in this provision shall
prevent the parties from establishing mutually agreed upon payment terms or the
applicant making payment sooner than 45 business days to maintain queue
position.
(d)
If the applicant’s system modification costs exceed $500,000 or the
estimated construction schedule for system modifications exceeds 2 years from
the signed IA, the applicant shall be eligible for a payment plan. This plan shall be included with the IA and
shall include a payment and construction schedule with milestones for both the utility
and the applicant that correlates to the schedule for payments with design,
procurement, and construction of the EDS modifications.
(e)
If the applicant fails to pay the utility within the timelines defined
in (c) and (d) above in this section, the IA shall be deemed withdrawn, subject
to the notice requirement of En 1014.02.
(f)
Upon execution of the IA, the applicant shall notify the utility of the
anticipated date the facility shall commence operations. Unless the utility agrees to a later date or
requires more time for necessary modifications to its EDS, the applicant shall
identify an anticipated in-service date that is within 24 months of the applicant’s
execution of the IA. The utility and the
applicant may mutually agree to an extension of this time if needed beyond the
24-month time period.
(g) The applicant shall notify the utility if
there is any change in the anticipated in-service date of interconnected
operations of the facility.
(h)
The IA milestone schedule for system modifications shall commence upon the
utility’s receipt of the applicant’s initial 25 percent payment. The utility shall make its best efforts to adhere
to the IA milestone schedule provided in the IA or detailed study.
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En 1011.09 Witness Test Plan. The applicant shall provide the utility with
proposed witness test procedures and plans that comply with IEEE Std 1547™-2018,
“IEEE Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 as available in Appendix
B and all requisite supporting documentation at least 30 business days before
the anticipated in-service date. Within 10
business days from receipt of the witness test plan, the utility shall notify
the applicant whether the witness test plan complies with applicable industry
and utility standards and if it complies, then the utility shall approve the witness
test plan.
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En 1011.10 Completeness and Compliance Review. The utility shall review the completed facility
as built for compliance with all applicable utility requirements and shall have
the option to attend any required commissioning tests pursuant to the currently
effective version of IEEE Std 1547™-2018, “IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 as available in
Appendix B. The utility shall conduct
the as-built review within 10 business days of receiving the notice of the
anticipated in-service date at a time mutually agreeable to the interconnecting
customer and utility. If the facility
passes the inspection, the utility shall provide written notice of such
approval within 3 business days.
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En 1011.11 Witness Test.
(a)
Once the as-built review has been passed and the witness test plan has
been approved, the utility shall schedule the witness test within 10 business
days at a time mutually agreeable to the interconnecting customer and utility.
(b)
If the facility initially fails the witness test, the utility shall
offer to repeat the test at the interconnecting customer’s expense at a time
mutually agreeable to the interconnecting customer and utility and repeat the
test as many times as is necessary until the facility passes the witness test.
(c)
If the utility determines that the facility fails the inspection, the
utility shall provide a written explanation detailing the reasons and any
standards violated. Provided that any
required commissioning tests are satisfactory, the utility shall grant PTO once
the facility passes the witness test and all other requirements of the IA are
satisfied.
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En 1011.12 Operation. Upon the utility’s receipt of proof of the
electric code official’s approval, an interconnecting customer may begin
interconnected operation of a facility, provided there is an IA in effect, the facility
has passed any facility review and witness test that may be required by the utility,
and the facility had received permission to operate. Evidence of approval by an electric code
official shall include a signed certificate of completion or other
inspector-provided documentation.
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PART En 1012 GROUP STUDY PROCESS
En 1012.01 Eligibility. An applicant shall be eligible to participate
in a group study if the facility meets the criteria of En 1011.05 and once the application
is deemed complete, or if the applicant and utility have not executed an IA and
the utility determines that the facility is located in the common study area of
another facility that has been assigned a later queue position and meets the
criteria of En 1011.05.
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En 1012.02 Group Study Notification. If the applicant is eligible to participate
in a group study, the utility shall notify the applicant within 20 business days
after the utility notifies the applicant that the application is complete. The utility shall notify the applicant of its
eligibility to participate in a group study upon notification of eligibility to
another applicant in the common study area.
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En 1012.03 Group Window. The utility shall identify all facilities
eligible for inclusion in the group within 40 business days of the initial group
study notification. The utility may
include additional facilities in the group after closing the group window with
approval from the applicant and other applicants eligible for the group study.
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En 1012.04 Public Availability.
(a)
Once the utility has notified the applicant of eligibility to
participate in a group study the utility shall publish on its website the
following:
(1) The name of the group;
(2) The number of projects in the group;
(3) The application identification and export
capacity of each project in the group;
(4) The relevant substation for the group, the
deadline for group formation, and date of execution of group study agreement;
and
(5) Date of completion of group study.
(b)
Any facility that is eligible for the group study shall be included on
the utility’s website within 10 business days.
The utility shall update this information monthly.
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En 1012.05 Scoping Meeting.
(a)
The purpose of the scoping meeting shall be to discuss the application,
the group, and review existing studies relevant to the application. At the scoping meeting, the utility shall
provide pertinent information such as aggregate export capacity of all other facilities
in the common study area, thermal limits of the substation transformer and
distribution feeders, quantity of applications and aggregate export capacity of
the facilities in the group, whether a substation transformer will need to be
upgraded, and whether there are any additional system modification anticipated.
(b)
The utility shall conduct a scoping meeting with all group members with
facilities in the common study area within 20 business days of the close of the
group window.
(c)
The scoping meeting shall take place in person, by telephone, or
electronically by a means mutually agreeable to the parties.
(d)
The utility and the applicant shall bring to the meeting personnel,
including system engineers, and other resources as might be reasonably required
to accomplish the purpose of the meeting.
(e)
By mutual agreement of the parties, the scoping meeting may be waived.
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En 1012.06 Group Study Election. The applicant shall notify the utility of its
election to participate in the group study within 10 business days of
completion of the scoping meeting.
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En 1012.07 Extended Group Study Election.
(a) The utility shall provide the applicant with
an extended group study consent form within 12 business days of completion of
the scoping meeting.
(b)
The applicant shall provide an executed extended group study consent
form within 10 business days of receiving the consent form from the utility.
(c)
The applicant shall be eligible for an extended group study if all
remaining facilities in the group submit an executed extended group study consent
form to the utility.
(d) If the applicant is deemed eligible for an extended
group study, the utility shall produce a non-binding estimate for the cost of system
modifications.
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En 1012.08 Group Study Agreement. The utility shall provide the applicant with
a group study agreement and an estimated cost for the group study within 25 business
days of completion of the scoping meeting.
The applicant shall submit an executed group study agreement to the utility
and pay the utility pursuant to the term of that agreement within 15 business
days of receipt of such agreement.
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En 1012.09 Group Study Fee. Each
applicant participating in a group study shall be responsible for its pro rata
portion of the group study fee based on the export capacity of each applicant’s
facility as a percentage of the total export capacity of all facilities in the
group. Should one or more individual
applicants of a group withdraw from the group either during the group study or
after the group study has been completed and as a result of any such
withdrawal, the utility shall revise or modify the group study or restudy the
group impact on the distribution system, each of the remaining applicants in
the group shall be responsible for its pro rata portion of the cost to revise
or modify the existing group study or restudy based on the export capacity of
each applicant’s facility as a percentage of the total export capacity of all
remaining facilities in the group.
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En 1012.10 Timelines.
(a)
For a group of DERs with no more than 3 applicants, an aggregated nameplate
capacity of 10 MW or less, and estimated aggregate system modifications less
than $1,500,000, the utility shall complete the group study within 100 business
days of the applicants’ delivery of the executed group study agreements.
(b)
For a group of DERs with no more than 5 applicants, an aggregated nameplate
capacity of 25 MW or less, and estimated aggregate system modifications less
than $1,500,000, the utility shall complete the group study within 125 business
days of the applicants’ delivery of the executed group study agreements.
(c)
For all other groups of DERs the utility shall complete the group study
within 160 business days of the applicants’ delivery of the executed group
study agreements.
(d)
The utility shall be provided with an additional 60 business days to
complete the group study if substation upgrades are required.
Source. #14657,
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En 1012.11 Facility Operating Characteristics. The group study shall take into account the
proposed facilities’ design and operating characteristics and study the facilities
according to how the facilities are proposed to be operated. If the facilities limit export pursuant to En
1013, the group study shall use export capacity instead of nameplate rating,
except when assessing fault current contribution.
Source. #14657,
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En 1012.12 Group Study Results. The group study results provided to the applicant
shall include a description of the utility’s analysis, conclusions, and the
reasoning supporting those conclusions and include a non-binding estimate of
the cost of the system modifications. The
utility shall use its best efforts to ensure the estimate is within +/- 25 percent
of final costs for a group study or +/- 15 percent of final costs for an extended
group study.
Source. #14657,
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En 1012.13 Group Study Results Meeting. The utility shall conduct a meeting to
discuss the group study results with the applicant and all other applicants
with facilities in the common study area within 20 business days of providing
the group study results to the applicant.
The group study results meeting shall:
(a) Take place in person, by telephone, or virtually;
(b)
The utility and the applicant shall bring to the meeting personnel,
including system engineers, and other resources as might be reasonably required
to accomplish the purpose of the meeting; and
(c)
By mutual agreement of the parties, the group study results meeting may
be waived.
Source. #14657,
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En 1012.14 Group Member Cost Responsibilities. The applicant shall be responsible for the
pro rata portion of the common system modifications identified in the group
study based on export capacity of the facility and total export capacity of the
group.
Source. #14657,
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En 1012.15 IA, Inspection, and Operation. Upon the completion of the group study:
(a)
The utility shall issue an IA in accordance with En 1011.08;
(b)
The applicant shall satisfy witness test procedures consistent with En
1011.09;
(c)
The utility shall conduct an inspection consistent with En 1011.10 and
1011.11; and
(d)
The facility shall begin operation in accordance with En 1011.12.
Source. #14657,
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PART En 1013 LIMITED-EXPORT, LIMITED-IMPORT, AND
NON-EXPORTING FACILITIES
En 1013.01 Export Capacity. If a facility uses any configuration or
operating mode pursuant to En 1013.03 to limit the export or import of
electrical power across the PCC, then the import capacity or export capacity
shall be only the amount capable of being imported or exported, excluding any inadvertent
export. To prevent impacts on system
safety and reliability, any inadvertent import and export from a facility shall
comply with the limits identified in this section. The export capacity or import capacity
specified by the applicant in the application shall subsequently be included as
a limitation in the IA.
Source. #14657,
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En 1013.02 Control and Protection Settings. An application proposing to use a
configuration or operating mode to limit the export or import of electrical
power across the PCC shall include proposed control or protection settings.
Source. #14657,
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En 1013.03 Acceptable Methods. Acceptable methods of export limitation or
import limitation shall include:
(a)
Limitation methods for non-exporting facilities as follows:
(1) For reverse power protection (Device 32R), to
limit export of power across the PCC, a reverse power protective function shall
be implemented using a utility-grade protective relay. The default setting for this protective
function shall be 0.1 percent (export) of the service transformer’s nominal
base nameplate rating, with a maximum 2.0 second time delay to limit inadvertent
export;
(2) For minimum power protection (Device 32F), to
limit import or export of power across the PCC, a minimum import protective
function shall be implemented using a utility-grade protective relay. The default setting for this protective
function shall be 5 percent (import) of the facility’s total nameplate rating,
with a maximum 2.0 second time delay to limit inadvertent export; and
(3) For the relative distributed energy resource
rating option, the facility’s nameplate rating shall be sufficiently small
relative to the host facility’s minimum load such that no additional protective
functions are required to prevent export to the electric delivery system. To qualify, the facility’s nameplate rating
shall not exceed 50 percent of the applicant’s verifiable minimum host load
over the preceding 12 months. This
option is not permitted for interconnections to area networks or spot networks;
(b)
Limitation methods for limited-export or limited-import facilities as
follows:
(1) For directional power protection (Device 32),
to limit export or import of power across the PCC, a directional power protective
function shall be implemented using a utility-grade protective relay. The default setting for this protective
function shall be the export/import capacity value, with a maximum 2.0 second
time delay to limit inadvertent export/import; and
(2) For configured power rating, a reduced output
rating utilizing the power rating configuration setting may be used to ensure
the facility does not generate power beyond a certain value lower than the nameplate
rating. The configuration setting
corresponds to the active or apparent power ratings in Table 28 of IEEE Std
1547™-2018, “IEEE Standard for Interconnection and
Interoperability of Distributed Energy Resources with Associated Electric Power
Systems Interfaces” dated 4/6/2018, as available in Appendix B. A local facility communication interface is
not required to utilize the configuration setting as long as it can be set by
other certified means. The reduced power
rating may be indicated by means of a nameplate rating replacement, or a
supplemental adhesive de-rating tag to indicate the reduced power rating. This method shall be certified in accordance
with IEEE Std 1547.1™-2020, “IEEE Standard Conformance Test Procedures for
Equipment Interconnecting Distributed Energy Resources with Electric Power
Systems and Associated Interfaces” dated 5/21/2020 as available in
Appendix B. Use of a configured power
rating not applied to individual generator(s) shall require evaluation under
mutually agreed upon means; and
(c)
Limitation methods for non-exporting facilities, limited-export facilities,
non-importing facilities, or limited-import facilities as follows:
(1) For certified power control systems, a facility
may use certified PCSs to limit export or import. A facility utilizing this option shall use a PCS
and an inverter certified per UL 1741, “Standard for Inverters, Converters,
Controllers with Interconnection System Equipment for Use with Distributed
Energy Resources” dated 4/22/2025 as available in Appendix B, by a NRTL with a
maximum open loop response time of no more than 30 seconds to limit inadvertent
export or inadvertent import. This
option shall not be available for interconnections to area networks or spot
networks; and
(2) For agreed-upon means, a facility may be
designed with other control systems or protective functions to limit export, inadvertent
export, import, or inadvertent import if mutual agreement is reached with the utility. The limits may be based on technical
limitations of the interconnection customer’s equipment or the electric
delivery system equipment. To ensure inadvertent
export or inadvertent import remains within mutually agreed-upon limits, the interconnection
customer may use an uncertified power control system, an internal transfer
relay, energy management system, or other customer facility hardware or
software if approved by the utility.
Source. #14657,
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PART En 1014 TIMELINES AND EXTENSIONS
En 1014.01 Utility Deadlines. The utility shall make reasonable efforts to
meet all timelines set by the interconnection procedures. If the utility cannot meet a timeline, the utility
shall attempt to notify the applicant in writing in advance of the deadline but
in any event no less than one business day after the missed deadline. The notification shall explain the reason for
the utility’s failure to meet the deadline and provide an estimate of when the
step will be completed. The utility
shall keep the applicant updated of any changes in the expected completion
date.
Source. #14657,
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En 1014.02 Applicant Deadlines.
(a)
An applicant may make a request to seek extension of a deadline of the
interconnection procedures. Such request
shall be in writing.
(b)
The utility shall grant an extension request if the applicant
demonstrates sufficient justification for the additional extension and the
extension duration is reasonable and does not unreasonably delay applications
behind the applicant seeking the extension in the queue.
(c) For any missed deadline that would result in
an application’s removal from its current queue position, the utility shall
notify the applicant a minimum of 8 business days prior to the application
being removed from its queue position.
Source. #14657,
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PART En 1015 ONLINE APPLICATIONS AND ELECTRONIC SIGNATURES
En 1015.01 Electronic Submission. Each utility shall require electronic applications
to be submitted via email or through other electronic means acceptable to the utility.
Source. #14657,
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En 1015.02 Utility Website Posting. Each utility shall post this chapter to a
well-identified page within the utility’s website. The relevant website page shall include:
(a) This chapter in an electronically searchable
format;
(b)
The utility’s standard forms; and
(c)
The utility’s point of contact for submission of applications including
email address and phone number.
Source. #14657,
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En 1015.03 Electronic Signatures for Interconnection
Applications and Agreements. Each utility shall allow
electronic signatures to be used for interconnection applications and agreements.
Source. #14657,
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PART En 1016 DISPUTE RESOLUTION
En 1016.01 Informal Dispute Resolution Efforts Required.
(a)
In the event of a dispute regarding any issue arising under this chapter,
the utility and the applicant shall make a good faith effort to first resolve
the dispute through informal means.
(b)
If the efforts of informal dispute resolution are unsuccessful, the applicant
may make a formal complaint with the department pursuant to RSA 365:1-4.
(c) Informal dispute resolution efforts shall not
suspend, extend, or delay any timeframes or deadlines applicable to the
application(s) at issue, except upon mutual agreement by the utility and the
applicant(s).
(d)
All timelines and deadlines shall remain in place and enforceable,
including all consequences of violating the applicable timeline or deadline,
which may be addressed in the informal dispute resolution process or brought as
a formal complaint to the department.
(e)
If a timeline or deadline is part of a good-faith dispute or will be
materially impacted as a consequence of a good-faith dispute, the utility and
the applicant shall make their best-faith efforts to accommodate modifications
to the relevant timelines or deadlines.
(f)
No application shall be deemed withdrawn or removed from the queue
solely because of a missed deadline that is associated with or results from a
good-faith dispute undergoing the process of this section.
(g)
An applicant’s execution of an IA or payment for system modifications in
accordance with applicable deadlines shall not preclude the applicant from
disputing any system modification or associated cost required under the IA.
Source. #14657,
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En 1016.02 Notice of Grievance. When a dispute occurs that is not resolved
through informal conversation, the party with the grievance shall notify the other
party of the dispute in writing with a description of the nature of the dispute
and relevant facts, the provisions of this chapter believed to be at issue, and
desired outcome. The receiving party
shall acknowledge the notification, identify a representative with the
authority to resolve the dispute, and commence good faith efforts to resolve
the dispute within 10 business days.
Source. #14657,
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En 1016.03 Grievance Resolution Process.
If a resolution is not reached in 10 business
days from the date of the notice of dispute, the following shall be available:
(a) A party may request in writing to continue
negotiations for an additional 25 business days;
(b)
The applicant may file an informal
complaint with the department’s consumer services division and request a
conference to attempt to resolve the dispute; and
(c)
Within 10 business days of a request for continued negotiations or within
10 business days of the conference referenced in (b) above in this section, the
applicant and the utility shall each provide a written description of technical
and regulatory details relevant to the dispute. Nothing shall prevent the parties from continuing
informal negotiations if a department-attended conference is requested.
Source. #14657,
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PART En 1017 UTILITY REPORTING REQUIREMENT
En 1017.01 Annual Report Reporting Period. Each utility shall provide to the department
an annual report by April 1 of each year.
The reporting period for all information required by this part shall be
for the most recent past calendar year.
Source. #14657,
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En 1017.02 Annual Report Required Information
Contained in the Pre-Application Reports. The annual report shall include the following
data submitted as part of the pre-application reports:
(a) Total number of
reports requested;
(b) Total number of
reports in process;
(c) Total number of
reports issued; and
(d) Average net
utility processing times from receipt of request to issuance of report.
Source. #14657,
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En 1017.03 Annual Report Required Information
Regarding Interconnection Applications.
The annual report shall include the following data regarding interconnection
applications:
(a) Total number of simplified
process applications submitted in the reporting period as follows:
(1) Total
average processing time from complete application to contingent approval for
applications completed in the reporting year;
(2) Average net utility processing time from
receipt of complete simplified process application to initial utility approval or
contingent approval for applications completed in the reporting year; and
(3) Average
customer hold time for applications completed in the reporting year; and
(b) Total
number of fast track process applications submitted in the reporting period as
follows:
(1) Total
average processing time from complete application to contingent approval for
applications completed in the reporting year;
(2) Average net utility processing time from
receipt of complete fast track process applications to provision of contingent
approval for applications that received contingent approval during the
reporting period; and
(3) Average
customer hold time for applications completed in the reporting year.
Source. #14657,
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PART En 1018 MISCELLANEOUS REQUIREMENTS
En 1018.01 Approvals. The applicant shall be responsible for
construction of the facility and obtaining any necessary local code official
approvals such as electrical and zoning approval.
Source. #14657,
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En 1018.02 Commissioning Test. The applicant shall conduct the commissioning
test pursuant to the IEEE Std 1547™-2018, “IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 as available in Appendix
B, and comply with all manufacturer requirements when conducting the
commissioning test.
Source. #14657,
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En 1018.03 Utility Designee. To assist applicants in the interconnection
process, the utility shall designate an employee or office from which basic
information on interconnections can be obtained. Upon request, the utility shall provide
interested applicants with all relevant forms, documents, and technical
requirements for filing a complete application. Upon an applicant’s request, the utility shall
meet with an applicant at the utility’s offices, by telephone, or via video
meeting prior to submission for up to one hour for simplified process applicants
and 2 hours for other applicants.
Source. #14657,
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En
1018.04 Additional Controls. A utility shall not be permitted to require
an applicant to install, at a cost to the applicant, any additional controls or
perform additional tests beyond those included in the interconnection agreement
to obtain approval to interconnect. The
utility shall be permitted, at a cost to the applicant, to require the installation
of controls necessary for safety and reliability that the utility could not
have known about at the time the interconnection agreement was executed.
Source. #14657,
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En 1018.05 Insurance Thresholds. A utility shall require an applicant to
purchase insurance covering utility damages as follows:
(a)
For non-inverter-based facilities, the following:
Insurance Thresholds
For Non-Inverter-Based Facilities
|
Nameplate Rating
> 5 MW |
$5,000,000 |
|
1 MW <
Nameplate Rating < 5 MW |
$2,000,000 |
|
100 kW <
Nameplate Rating < 1 MW |
$1,000,000 |
|
10 kW <
Nameplate Rating < 100 kW |
$500,000 |
|
Nameplate Rating
< 10 kW |
Typical
Homeowners |
(b) For inverter-based facilities, the following:
Insurance Thresholds
For Inverter-Based Facilities
|
Nameplate Rating
> 5 MW |
$2,000,000 |
|
MW <
Nameplate Rating < 5 MW |
$1,000,000 |
|
Nameplate Rating
< 1 MW |
No insurance |
Source. #14657,
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En
1018.06 Additional Equipment. Additional protection equipment not included
with the interconnection equipment package may be required at the utility’s
discretion as long as the operational performance of an applicant’s DER is not
negatively impacted and the applicant is not charged for any equipment that
provides protection that is already identified in the approved interconnection
equipment.
Source. #14657,
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En 1018.07 Metering. Metering and monitoring shall be as set forth
in En 300, utility tariffs, the IA, when applicable, and additional applicable utility
resources.
Source. #14657,
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En 1018.08 Telemetry. Requirements for telemetry shall be
consistent with the utility’s TIR as defined in En 1002.53.
Source. #14657,
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En
1018.09 Operational Testing. Once an interconnection has been approved
under this chapter, a utility shall not require an interconnection customer to
test its facility except that the utility may require any
manufacturer-recommended testing and:
(a) For the fast track process, the utility may
require periodic testing to verify adherence to the interconnection
requirements. The frequency of periodic
testing shall be specified in the utility’s interconnection handbook or other
appropriate documentation;
(b) For the standard process, all
interconnection-related protective functions and associated batteries shall be
periodically tested at intervals specified by the manufacturer, system
integrator, or authority having jurisdiction over the interconnection. Periodic test reports or a log for inspection
shall be maintained; and
(c) For functional software or firmware changes,
hardware changes, protection settings, or function changes, or changes to
operating modes, the utility may require retesting to ensure the facility still
meets the requirements of IEEE Std 1547™-2018, “IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces” dated 4/6/2018 as available in Appendix
B. When required, the updated facility configuration
and testing results shall be documented and submitted to the utility.
Source. #14657,
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En 1018.10 Utility Right to Inspect. A utility shall have the right to inspect an interconnecting
customer’s facility before and after interconnection approval is granted during
normal business hours with prior written notice provided to the interconnection
customer no less than one week before the scheduled inspection. In the event of an emergency, no such notice
is necessary. If the utility discovers
an interconnecting customer’s facility is not in compliance with the operating
requirements of the IA or applicable standards, and the non-compliance
adversely affects the safety or reliability of the electric system, the utility
may require disconnection of the interconnecting customer’s facility until the facility
complies with the operating requirements of the IA or applicable standards.
Source. #14657,
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En 1018.11 Cost Reconciliation.
(a)
The utility shall, only upon request by the applicant, true up estimates
for all, studies and EDS modifications for project applications with
substantial modifications to reflect actual costs either through
refunding or invoicing the applicant for the difference within 240 business
days of PTO or of termination of the IA if the termination of the IA occurs
prior to PTO. Invoices provided to the
applicant shall be accompanied by a final accounting report that provides a
detailed breakdown of costs. That cost
breakdown shall match, at minimum, the level of detail of the estimate provided
to the applicant.
(b)
An applicant may request a final accounting report of any difference
between:
(1) The actual costs of the studies and upgrades;
and
(2) The applicant’s previous aggregate payments to
the utility for studies and upgrades within 120 business days after PTO or within
120 business days of the termination of the IA if the termination of the IA
occurs prior to PTO.
(c) Upon receipt of a request for a final
accounting report from an applicant, the utility shall have 120 business days
to provide the requested final accounting report to the applicant as follows:
(1) If the funds spent or committed by the
utility exceeds the applicant’s previous aggregate payments, the utility shall
invoice the applicant, and the applicant shall provide full payment to the utility
within 45 business days;
(2) If the applicant’s previous aggregate
payments exceed the funds spent or committed by the utility, the utility shall
refund to the applicant an amount equal to the difference within 45 business
days; and
(3) Failure by the applicant to pay undisputed
amounts within the required timeframe authorizes the utility to disconnect the facility
from the EDS any time after the lapsed deadline.
Source. #14657,
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En 1018.12 Voluntary Disconnection. The interconnecting customer may disconnect
the facility at any time without prior notice to the utility and may terminate
the IA at any time with 10 days notice to the utility.
Source. #14657,
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En 1018.13 Designated Representative. An applicant may designate a representative
to process an application on applicant’s behalf, and an interconnection customer
may designate a representative to meet some or all of the interconnection customer’s
responsibilities under the IA.
Source. #14657,
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En 1018.14 Assignment. Nothing in this chapter shall prohibit the interconnecting
customer from assigning its ownership of the facility as well as all rights and
obligations under the IA to a successor owner or occupant of the facility site.
Source. #14657,
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En 1018.15 Energy Storage.
(a)
If the applicant is seeking approval for an energy storage device, that
is co-located with load, other than station service load, pursuant to an application
governed by this chapter, the utility shall not require a separate and
additional request for new service for the interconnection of new or modified
load. The utility shall review the
co-located energy storage device pursuant to the processes in this chapter and
not pursuant to En 300.
(b)
If the applicant is seeking approval for an energy storage device not co-located
with load, other than station service load, the utility shall apply the
interconnection requirements established in the utility TIR.
(c)
Energy storage devices
shall be screened or studied according to the proposed facility’s design and
operating characteristics. If the
facility limits export or import pursuant to En 1013, screening or study of the
device shall use export capacity or import capacity instead of nameplate
rating, except when assessing fault current contribution.
Source. #14657,
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APPENDIX
A
|
Rule(s) |
Statute |
|
En 1001 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1002 |
RSA
12-P:5, IV; RSA 362-A:1; RSA 362-A:9; RSA 374-F:2, VII-VIII; Laws 2024, ch.
287 |
|
En 1003 |
RSA
12-P:5, IV; Laws 2024, ch. 287 |
|
En 1004 |
RSA
12-P:5, IV; RSA 362-A:9; RSA 378:3; Laws 2024, ch. 287 |
|
En 1005 - En
1007 |
RSA 12-P:5, IV; RSA
362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1008.01 - En 1008.05 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1008.06 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); RSA 362-A:9, XIII; Laws 2024, ch. 287 |
|
En 1008.07 - En 1008.10 |
RSA 12-P:5, IV; RSA 362-A:9, X(a); Laws
2024, ch. 287 |
|
En 1009 - En 1010 |
RSA 12-P:5, IV; RSA 362-A:9, X(a); RSA
374:2; Laws 2024, ch. 287 |
|
En 1011.01 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1011.02 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); RSA 362-A:9, XIII; Laws 2024, ch. 287 |
|
En 1011.03 – En 1012.08 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1012.09 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); RSA 362-A:9, XIII; Laws 2024, ch. 287 |
|
En 1012.10 – En 1012.13 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1012.14 |
RSA
12-P:5, IV; RSA 362-A:9, X(a); RSA 362-A:9, XIII; Laws 2024, ch. 287 |
|
En 1013 |
RSA 12-P:5, IV; RSA
362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1014 |
RSA 12-P:5, IV; RSA
362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1015 |
RSA 12-P:5, IV; RSA
362-A:9, X(a); Laws 2024, ch. 287 |
|
En 1016 |
RSA 12-P:5, IV; RSA
365:1-4; Laws 2024, ch. 287 |
|
En 1017 |
RSA 12-P:5, IV; Laws 2024, ch. 287 |
|
En 1018 |
RSA
12-P:5, IV; RSA
362-A:9, XIII; RSA 362-A:1; Laws 2024, ch. 287 |
APPENDIX B:
INCORPORATION BY REFERENCE INFORMATION
|
Rule |
Title (date) |
Source |
|
En 1002.09, En 1002.50, En 1005.01(a), En
1009.03(b)(2), En
1009.03(b)(3), En 1011.06(d), En 1011.09, En 1011.10, En
1013.03(b)(2), En 1018.02, En 1018.09(c) |
IEEE Std 1547™-2018 - IEEE
Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power System Interfaces, dated 4/6/2018 |
Institute of
Electrical and Electronic Engineers, Inc., 445 Hoes Lane, Piscataway, NJ
08854 Available for
purchase at: https://store.accuristech.com/standards/ieee-1547-2018?product_id=1983168 for $172.00 PDF $215.00 Printed
Edition $271.00 Printed
Edition and PDF |
|
En 1002.09, En 1005.01(b), En 1013.03(b)(2) |
IEEE Std 1547.1™-2020 - IEEE
Standard Conformance Test Procedures for Equipment Interconnecting
Distributed Energy Resources with Electric Power Systems and Associated
Interfaces, dated 5/21/2020 |
Institute of
Electrical and Electronic Engineers, Inc., 445 Hoes Lane, Piscataway, NJ
08854 Available for
purchase at: https://store.accuristech.com/standards/ieee-1547-1-2020?product_id=2045401 for $225.00 PDF $281.00 Printed
Edition $350.00 Printed
Edition and PDF |
|
En 1005.01(d) |
IEEE Std 1547.2™-2023 – IEEE Application
Guide for IEEE Std 1547™-2018, IEEE Standard for Interconnection and
Interoperabililty of Distributed Energy Resources with Associated Electric
Power Systems Interfaces, dated 5/20/2024 |
Institute of
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En 1005.01(e) |
IEEE Std 1547.3™-2023 – IEEE
Guide for Cybersecurity of Distributed Energy Resources Interconnected with
Electric Power Systems, dated 12/11/2023 |
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En 1005.01(f) |
IEEE Std 1547.7™-2013 – IEEE
Guide for Conducting Distribution Impact Studies for Distributed Resource
Interconnection, dated 2/28/2014 |
Institute of
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08854 Available for
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En 1005.01(g) |
IEEE Std 519™-2022 – IEEE
Standard for Harmonic Control in Electric Power Systems, dated 8/5/2022 |
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En 1005.01(h) |
IEEE Std 1453™-2022 – IEEE
Standard for Measurement and Limits of Voltage Fluctuations and Associated
Light Flicker on AC Power Systems, dated 2/27/2023 |
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En 1005.01(i) |
IEEE Std C37.90.2™-2024 - IEEE
Standard for Relays, Relay Systems, and Control Devices used for Protection
and Control of Electric Power Apparatus-Radiated Electromagnetic Interference
Withstand Capability Requirements and Tests, dated 1/31/2025 |
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En 1005.01(j) |
IEEE Std C37.95™-2014 - IEEE
Guide for Protective Relaying of Utility-Consumer Interconnections, dated
5/5/2014 |
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En 1005.01(k) |
IEEE Std C50.13™-2014 - IEEE
Standard for Cylindrical-Rotor 50 Hz and 60 Hz Synchronous Generators Rated
10 MVA and Above, dated 5/9/2014 |
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En 1005.01(l) |
IEEE Std C62.92.1™-2016 - IEEE
Guide for the Application of Neutral Grounding in Electrical Utility
Systems-Part I: Introduction, dated 3/31/2017 |
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En 1005.01(m) |
IEEE Std C62.92.2™-2017 - IEEE
Guide for the Application of Neutral Grounding in Electrical Utility Systems,
Part II-Synchronous Generator Systems, dated 5/19/2017 |
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En 1005.01(n) |
IEEE Std C62.92.6™-2017 - IEEE
Guide for Application of Neutral Grounding in Electrical Utility Systems,
Part VI-Systems Supplied by Current-Regulated Sources, dated 12/22/2017 |
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En 1002.09, En 1005.01(o), En 1005.01(p), En 1007.03(a), En 1013.03(c)(1) |
UL 1741 -
Inverters, Converters, Controllers and Interconnection System Equipment for
Use with Distributed Energy Resources, dated 4/22/2025 |
Underwriters
Laboratories, Inc., 333 Pfingsten Road, Northbrook, IL 60062 Standard 1741, Edition 3 Edition Date: September 28, 2021 Includes Supplement SB Available for purchase at: https://www.shopulstandards.com/ProductDetail.aspx?productId=UL1741_3_S_20210928 for $798.00 Secure PDF (Read Only) $998.00 Secure PDF and Hardcopy Combo $998 Premium Hardcopy |
|
En 1005.01(q) |
UL 3141 - UL LLC
Outline of Investigation for Power Control Systems, dated 10/9/2024 |
Underwriters
Laboratories, Inc., 333 Pfingsten Road, Northbrook, IL 60062 Standard 3141, Edition 1 Edition Date: December 6, 2024 Available for purchase at: https://www.shopulstandards.com/ProductDetail.aspx?productId=UL3141_2_O_20241009 for $225.00 Secure
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En 1005.01(c) |
ANSI C84.1-2020
- Electric Power Systems and Equipment - Voltage Ratings (60 Hertz), dated
3/10/2020 |
American
National Standards Institute, 1899 L Street, NW, 11th Floor, Washington,
DC 20036 Standard C84.1, 2020 Edition Edition Date: March 10, 2020 Available for purchase at: https://webstore.ansi.org/search/find?in=1&st=ANSI+C84.1-2020 for $179.00 PDF $198.32 Stapled Hardcopy $201.54 Spiral Hardcopy $205.84 Binder Hardcopy |