RM22-12 Final Rule (Published)

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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM22–12–000; Order No. 901]

Reliability Standards To Address
Inverter-Based Resources
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Final action.
AGENCY:

The Federal Energy
Regulatory Commission (Commission) is
directing the North American Electric
Reliability Corporation (NERC), the

SUMMARY:

Commission-certified Electric
Reliability Organization, to develop new
or modified Reliability Standards that
address reliability gaps related to
inverter-based resources in the
following areas: data sharing; model
validation; planning and operational
studies; and performance requirements.
The Commission is also directing NERC
to submit to the Commission an
informational filing within 90 days of
the issuance of this final action that
includes a detailed, comprehensive
standards development plan providing
that all new or modified Reliability
Standards necessary to address the
inverter-based resource-related
reliability gaps identified in this final

action be submitted to the Commission
by November 4, 2026.
DATES: This rule is effective December
29, 2023.
FOR FURTHER INFORMATION CONTACT:
Eugene Blick (Technical Information),
Office of Electric Reliability, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
(202) 502–8803, [email protected].
Felicia West (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
(202) 502–8948, [email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents

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Paragraph
Nos.
I. Information ..........................................................................................................................................................................................
II. Background .........................................................................................................................................................................................
A. Section 215 of the FPA and the Mandatory Reliability Standards .........................................................................................
B. Inverter-Based Resources ...........................................................................................................................................................
C. Notice of Proposed Rulemaking ................................................................................................................................................
III. Need for Reform ................................................................................................................................................................................
A. Current Actions Are Insufficient To Address IBR Reliability Risks .......................................................................................
B. Existing Reliability Standards Do Not Adequately Address IBR Reliability Risks ................................................................
1. Data Sharing .........................................................................................................................................................................
2. Data and Model Validation .................................................................................................................................................
3. Planning and Operational Studies ......................................................................................................................................
4. Performance Requirements ..................................................................................................................................................
IV. Discussion .........................................................................................................................................................................................
A. Commission Authority To Direct the ERO To Develop New or Modified Reliability Standards Under Section 215 of
the FPA .........................................................................................................................................................................................
1. Comments .............................................................................................................................................................................
2. Commission Determination .................................................................................................................................................
B. Data Sharing ................................................................................................................................................................................
1. Registered IBR Data Sharing ...............................................................................................................................................
2. Disturbance Monitoring Data Sharing ................................................................................................................................
3. Unregistered IBR and IBR–DER Data Sharing ....................................................................................................................
C. Data and Model Validation ........................................................................................................................................................
1. Approved Component Models ............................................................................................................................................
2. Verification of IBR Plant Dynamic Model Performance ....................................................................................................
3. Validating and Updating System Models ...........................................................................................................................
4. Need for Coordination When Creating and Updating Planning, Operational, and Interconnection-Wide Data and
Models ...................................................................................................................................................................................
D. Planning and Operational Studies .............................................................................................................................................
1. Comments .............................................................................................................................................................................
2. Commission Determination .................................................................................................................................................
E. Performance Requirements .........................................................................................................................................................
1. Registered IBR Frequency and Voltage Ride Through Requirements ..............................................................................
2. Bulk-Power System Planners and Operators Voltage Ride Through Mitigation Activities ............................................
3. Post-Disturbance IBR Ramp Rate Interactions and Phase Lock Loop Synchronization ..................................................
F. Informational Filing and Reliability Standard Development Timeline ...................................................................................
1. Comments .............................................................................................................................................................................
2. Commission Determination .................................................................................................................................................
V. Information Collection Statement .....................................................................................................................................................
VI. Environmental Analysis ...................................................................................................................................................................
VII. Regulatory Flexibility Act ...............................................................................................................................................................
VIII. Document Availability ...................................................................................................................................................................
IX. Effective Date and Congressional Notification ...............................................................................................................................
Appendix A: Commenter Names.
Appendix B: NERC IBR Resources Cited in the Final Action.

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I. Introduction
1. Pursuant to section 215(d)(5) of the
Federal Power Act (FPA),1 the Federal
Energy Regulatory Commission
(Commission) directs the North
American Electric Reliability
Corporation (NERC), the Commissioncertified Electric Reliability
Organization (ERO), to submit new or
modified Reliability Standards 2 that
address specific matters pertaining to
the impacts of inverter-based resources
(IBR) 3 on the reliable operation 4 of the
Bulk-Power System.5 As proposed in
the notice of proposed rulemaking
(NOPR), we direct NERC to develop new
or modified Reliability Standards
addressing reliability gaps pertaining to
IBRs in four areas: (1) data sharing; (2)
model validation; (3) planning and
operational studies; and (4) performance
requirements.6 NERC may propose to
develop new or modified Reliability
Standards that address our concerns in
an equally efficient and effective
manner; however, NERC’s proposal
should explain how the new or
modified Reliability Standards address
1 16 U.S.C. 824o(d)(5) (the Commission may order
the Electric Reliability Organization (ERO) to
submit to the Commission a proposed Reliability
Standard or a modification to a Reliability Standard
that addresses a specific matter if the Commission
considers such a new or modified Reliability
Standard appropriate to carry out FPA section 215).
2 The FPA defines Reliability Standard as
requirements for the operation of existing BulkPower System facilities, including cybersecurity
protection, and the design of planned additions or
modifications to such facilities to the extent
necessary to provide for reliable operation of the
Bulk-Power System, but the term does not include
any requirement to enlarge such facilities or to
construct new transmission capacity or generation
capacity. Id. 824o(a)(3); see also 18 CFR 39.1.
3 This final action uses the term IBR generally to
include all generation resources that connect to the
electric power system using power electronic
devices that change direct current (DC) power
produced by a resource to alternating current (AC)
power compatible with distribution and
transmission grids. IBRs may refer to solar
photovoltaic (PV), wind, fuel cell, and battery
storage resources.
4 The FPA defines reliable operation as operating
the elements of the Bulk-Power System within
equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled
separation, or cascading failures of such system will
not occur as a result of a sudden disturbance,
including a cybersecurity incident, or unanticipated
failure of system elements. 16 U.S.C. 824o(a)(4); see
also 18 CFR 39.1.
5 The Bulk-Power System is defined in the FPA
as facilities and control systems necessary for
operating an interconnected electric energy
transmission network (or any portion thereof), and
electric energy from generating facilities needed to
maintain transmission system reliability. The term
does not include facilities used in the local
distribution of electric energy. 16 U.S.C. 824o(a)(1);
see also 18 CFR 39.1.
6 Reliability Standards to Address Inverter-based
Res., Notice of Proposed Rulemaking, 87 FR 74541
(Dec. 6, 2022), 181 FERC ¶ 61,125, at P 1 (2022)
(NOPR).

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the Commission’s concerns discussed in
this final action.7
2. We take this action in light of the
rapid change in the mix of generation
resources 8 connecting to the BulkPower System, including the addition of
an ‘‘unprecedented proportion of
nonsynchronous resources’’ 9 projected
to connect over the next decade,
including many generation resources
that employ inverters, rectifiers, and
converters 10 to provide energy to the
Bulk-Power System. According to
NERC, the rapid integration of IBRs is
‘‘the most significant driver of grid
transformation’’ on the Bulk-Power
System.11
3. The Reliability Standards, first
approved by the Commission in 2007,
were developed to apply to the types of
generation resources prevalent at that
time—nearly exclusively synchronous
generation resources—to ensure the
reliable operation of the Bulk-Power
System. As a result, the Reliability
Standards may not account for the
material technological differences
between the response of synchronous
generation resources and the response of
IBRs to the same disturbances on the
Bulk-Power System.12

4. We also take this action because, as
discussed in more detail in section III
below, we find that the currently
effective Reliability Standards do not
ensure that Bulk-Power System planners
and operators 13 have the necessary tools
to plan for and reliably integrate IBRs
into the Bulk-Power System or to plan
for IBRs connected to the distribution
system that in the aggregate have a
material impact on the Bulk-Power
System (IBR–DER). IBRs, individually
and in the aggregate, and IBR–DERs in
the aggregate can have a material impact
on the reliable operation of the BulkPower System.14 Additionally, the
Reliability Standards do not contain
performance requirements that are
unique to IBRs and are necessary to
ensure that IBRs operate in a predictable
and reliable manner.
5. As discussed in greater detail
below, we therefore direct NERC,
pursuant to section 215(d)(5) of the FPA
and § 39.5(f) of the Commission’s
regulations, to develop new or modified
Reliability Standards that address the
following specific issues:
• IBR Data Sharing: The Reliability
Standards must require that generator
owners, transmission owners, and

7 See, e.g., Mandatory Reliability Standards for
the Bulk-Power Sys., Order No. 693, 72 FR 16416
(Apr. 4, 2007), 118 FERC ¶ 61,218, at PP 186, 297,
order on reh’g, Order No. 693–A, 72 FR 40717 (July
25, 2007), 120 FERC ¶ 61,053 (2007) (‘‘[W]here the
Final Rule identifies a concern and offers a specific
approach to address the concern, we will consider
an equivalent alternative approach provided that
the ERO demonstrates that the alternative will
address the Commission’s underlying concern or
goal as efficiently and effectively as the
Commission’s proposal.’’).
8 The Reliability Standards use both terms
‘‘generation resources’’ and ‘‘generation facilities’’
to define sources of electric power on the
transmission system. This final action uses the term
‘‘generation resources.’’
9 NERC, 2020 Long Term Reliability Assessment
Report, 9 (Dec. 2020), https://www.nerc.com/pa/
RAPA/ra/Reliability%20Assessments%20DL/
NERC_LTRA_2020.pdf (2020 LTRA Report).
10 An inverter is a power electronic device that
inverts DC power to AC sinusoidal power. A
rectifier is a power electronic device that rectifies
AC sinusoidal power to DC power. A converter is
a power electronic device that performs
rectification and/or inversion. Consistent with
NERC’s terminology, this order uses the term
‘‘inverter’’ to refer to generating facilities that use
power electronic inversion, rectification, and
conversion. NERC, Inverter-Based Resource
Performance and Analysis Technical Workshop, 29
(Feb. 2019), https://www.nerc.com/comm/PC/
IRPTF%20Workshops/IRPTF_Workshop_
Presentations.pdf.
11 NERC, Inverter-Based Resource Strategy:
Ensuring Reliability of the Bulk Power System with
Increased Levels of BPS-Connected IBRs, 1 (June
2022), https://www.nerc.com/comm/Documents/
NERC_IBR_Strategy.pdf (NERC IBR Strategy).
12 See, e.g., NERC, 2013 Long-Term Reliability
Assessment, 22 (Dec. 2013), https://www.nerc.com/
pa/RAPA/ra/Reliability%20Assessments%20DL/
2013_LTRA_FINAL.pdf (2013 LTRA Report)
(finding that reliably integrating high levels of

variable resources into the Bulk-Power System
would require ‘‘significant changes to traditional
methods used for system planning and operation,’’
including requiring ‘‘new tools and practices,
including potential enhancements to . . .
Reliability Standards or guidelines to maintain
[Bulk-Power System] reliability.’’).
13 Bulk-Power System planners and operators
include planning coordinators, transmission
planners, reliability coordinators, transmission
operators, and balancing authorities, and any other
functional entity NERC may identify as applicable
to meet the directives in this final action.
14 NERC reports do not always differentiate
between IBRs based on type, or between those
subject to Reliability Standards and those located
on the distribution system. Where necessary to
describe our directives, however, we differentiate
between IBRs registered with NERC (or which will
be registered pursuant to the Commission’s
directives in Registration of Inverter-based
Resources, 181 FERC ¶ 61,124 (2022) (IBR
Registration Order)) and therefore subject to the
Reliability Standards (i.e., registered IBR), IBRs
connected directly to the Bulk-Power System but
not registered with NERC and therefore not subject
to the Reliability Standards (i.e., unregistered IBRs),
and IBRs connected to the distribution system that
in the aggregate have a material impact on the BulkPower System (i.e., IBR–DER). Although the
remaining subset of unregistered IBRs and IBR–
DERs in the aggregate will not be subject to the
mandatory and enforceable Reliability Standards set
forth herein, they may be subject to provision of
data and information to their respective
transmission owners and distribution providers, as
applicable, in accordance with their specific
interconnection agreements. We encourage NERC to
continue its efforts to review and evaluate whether
reliability gaps continue to remain and if new or
modified functional registration categories or
Reliability Standards are necessary. See infra note
365 (discussing NERC’s estimate of the percentage
of IBRs to be registered under its registration work
plan).

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distribution providers share validated
modeling, planning, operations, and
disturbance monitoring data for all IBRs
with planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities so that the
latter group has the necessary data to
predict the behavior of registered and
unregistered IBRs individually and in
the aggregate, as well as IBR–DERs in
the aggregate, and their impact on the
reliable operation of the Bulk-Power
System.
• IBR Model Validation: The
Reliability Standards must require that
all IBR models are comprehensive,
validated, and updated in a timely
manner, so that planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities can
adequately predict the behavior of
registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate, and
their impacts on the reliable operation
of the Bulk-Power System.
• IBR Planning and Operational
Studies: The Reliability Standards must
require that planning and operational
studies include validated IBR models to
assess the reliability impacts of
registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate, on
the reliable operation of the Bulk-Power
System. The Reliability Standards must
require that planning and operational
studies assess the impacts of all IBRs
within and across planning and
operational boundaries for normal
operations and contingency event
conditions.
• IBR Performance Requirements:
The Reliability Standards must ensure
that registered IBRs will provide
frequency and voltage support during
frequency and voltage excursions in a
manner necessary to contribute toward
the overall system needs for essential
reliability services.15 The Reliability
Standards must establish clear and
reliable technical limits and capabilities
for registered IBRs to ensure that all
registered IBRs are operated in a
predictable and reliable manner during
normal operations and contingency
event conditions. The Reliability
Standards must require that the
15 See, e.g., NERC, A Concept Paper on Essential
Reliability Services that Characterizes Bulk Power
System Reliability, vi (Oct. 2014), https://
www.nerc.com/comm/Other/
essntlrlbltysrvcstskfrcDL/
ERSTF%20Concept%20Paper.pdf (Essential
Reliability Services Concept Paper) (listing the
essential reliability services necessary to maintain
Bulk-Power System reliability).

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operational aspects of registered IBRs
contribute towards meeting the overall
system needs for essential reliability
services. The Reliability Standards must
include post-disturbance ramp rates and
phase lock loop synchronization
requirements for registered IBRs.
6. Pursuant to § 39.2(d) of the
Commission’s regulations,16 we direct
NERC to submit an informational filing
within 90 days of the issuance of the
final action in this proceeding. NERC’s
filing shall include a detailed and
comprehensive standards development
plan explaining how NERC will
prioritize the development of new or
modified Reliability Standards to meet
the deadlines set forth in this final
action. We direct NERC to explain in its
filing how it is prioritizing its IBR
Reliability Standard projects to meet the
directives in this final action, taking
into account the risk posed to the
reliability of the Bulk-Power System,
standard development projects already
underway, resource constraints, and
other factors if necessary.
7. NERC’s standards development
plan must ensure that NERC submits
new or modified Reliability Standards
by the following deadlines. First, by
November 4, 2024, NERC must submit
new or modified Reliability Standards
that establish IBR performance
requirements, including requirements
addressing frequency and voltage ride
through,17 post-disturbance ramp rates,
phase lock loop synchronization, and
other known causes of IBR tripping or
momentary cessation.18 NERC must also
submit, by November 4, 2024, new or
modified Reliability Standards that
require disturbance monitoring data
sharing and post-event performance
validation for registered IBRs. Second,
by November 4, 2025, NERC must
submit new or modified Reliability
16 18 CFR 39.2(d) (the electric reliability
organization shall provide the Commission
information as necessary to implement section 215
of the FPA).
17 See Standardization of Generator
Interconnection Agreements & Procs., Order No.
2003, 104 FERC ¶ 61,103, at P 562 n.88 (2003)
(defining ride through as ‘‘a Generating Facility
staying connected to and synchronized with the
Transmission System during system disturbances
within a range of over- and under-frequency[/
voltage] conditions, in accordance with Good
Utility Practice.’’).
18 Momentary cessation is a mode of operation
during which the inverter remains electrically
connected to the Bulk-Power System, but the
inverter does not inject current during low or high
voltage conditions outside the continuous operating
range. As a result, there is no current injection from
the inverter and therefore no active or reactive
current (and no active or reactive power). NERC,
Reliability Guideline: BPS-Connected InverterBased Resource Performance, 11 (Sept. 2018),
https://www.nerc.com/comm/RSTC_Reliability_
Guidelines/Inverter-Based_Resource_Performance_
Guideline.pdf (IBR Performance Guideline).

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Standards addressing the interrelated
directives concerning: (1) data sharing
for registered IBRs, unregistered IBRs,
and IBR–DERs in the aggregate; and (2)
data and model validation for registered
IBRs, unregistered IBRs, and IBR–DERs
in the aggregate. Finally, by November
4, 2026, NERC must submit new or
modified Reliability Standards
addressing planning and operational
studies for registered IBRs, unregistered
IBRs, and IBR–DERs in the aggregate.
We continue to believe this staggered
approach to standard development and
implementation is necessary based on
the scope of work anticipated and that
specific target dates will provide a
valuable tool and incentive to NERC to
timely address the directives in this
final action.
8. Although we are not directing
NERC to include implementation dates
in its informational filing and are
leaving determination of the appropriate
effective dates to the standards
development process, we are concerned
that the lack of a time limit for
implementation could allow identified
issues to remain unresolved for a
significant and indefinite period.
Therefore, we emphasize that industry
has been aware of and alerted to the
need to address the impacts of IBRs on
the Bulk-Power System since at least
2016. The number of events, NERC
Alerts, reports, whitepapers, guidelines,
and ongoing standards projects, as
discussed in more detail in section III
and throughout this final action, more
than demonstrate the need for the
expeditious implementation of new or
modified Reliability Standards
addressing IBR data sharing, data and
model validation, planning and
operational studies, and performance
requirements. Thus, in that light, the
Commission will take these issues into
account when it considers the proposed
implementation plan for each new or
modified Reliability Standard when it is
submitted for Commission. Further, as a
general matter, we believe that there is
a need to have all the directed
Reliability Standards effective and
enforceable well in advance of 2030 and
direct NERC to ensure that the
associated implementation plans
sequentially stagger the effective and
enforceable dates to ensure an orderly
industry transition for complying with
the IBR directives in this final action
prior to 2030.
II. Background
A. Section 215 of the FPA and the
Mandatory Reliability Standards
9. Section 215 of the FPA provides
that the Commission may certify an

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ERO, the purpose of which is to develop
mandatory and enforceable Reliability
Standards, subject to Commission
review and approval.19 Reliability
Standards may be enforced by the ERO,
subject to Commission oversight, or by
the Commission independently.20
Pursuant to section 215 of the FPA, the
Commission established a process to
select and certify an ERO,21 and
subsequently certified NERC.22
10. Pursuant to section 215(d)(5) of
the FPA, the Commission has the
authority, upon its own motion or upon
complaint, to order the ERO to submit
to the Commission a proposed
Reliability Standard or a modification to
a Reliability Standard that addresses a
specific matter if the Commission
considers such a new or modified
Reliability Standard appropriate to carry
out section 215 of the FPA.23 Further,
pursuant to § 39.5(g) of the
Commission’s regulations, the
Commission may order a deadline by
which the ERO must submit a proposed
or modified Reliability Standard.24
B. Inverter-Based Resources
11. The Bulk-Power System
generation fleet has traditionally been
composed almost exclusively of
synchronous generation resources that
convert mechanical energy into electric
energy through electromagnetic
induction. By virtue of the kinetic
energy in their large rotating
components, these synchronous
generation resources inherently resist
changes in system frequency, providing
time for other governor controls (when
properly configured) to maintain supply
and load balance. Similarly,
synchronous generation resources
inherently provide voltage support
during voltage disturbances.
12. In contrast, IBRs do not use
electromagnetic induction from
machinery that is directly synchronized
to the Bulk-Power System. Instead, the
majority of installed IBRs use gridfollowing inverters, which rely on
sensed information from the grid (e.g., a
voltage waveform) to produce the
desired AC real and reactive power
19 16

U.S.C. 824o(c).
824o(e).
21 Rules Concerning Certification of the Elec.
Reliability Org. & Procs. for the Establishment,
Approval, & Enf’t. of Elec. Reliability Standards,
Order No. 672, 114 FERC ¶ 61,104, order on reh’g,
Order No. 672–A, 114 FERC ¶ 61,328 (2006).
22 N. Am. Elec. Reliability Corp., 116 FERC
¶ 61,062, order on reh’g and compliance, 117 FERC
¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. FERC,
564 F.3d 1342 (D.C. Cir. 2009).
23 16 U.S.C. 824o(d)(5).
24 18 CFR 39.5(g).

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output.25 Due to their inverters, IBRs
can track grid state parameters (e.g.,
voltage angle) in milliseconds and react
nearly instantaneously to changing grid
conditions. Some IBRs, however, are not
configured or programmed to support
grid voltage and frequency in the event
of a system disturbance, and, as a result,
will reduce power output,26 exhibit
momentary cessation, or trip in
response to variations in system voltage
or frequency.27 In other words, under
certain conditions some IBRs cease to
provide power to the Bulk-Power
System due to how they are configured
and programmed. Nonetheless, some
models and simulations incorrectly
predict that some IBRs will ride through
disturbances, i.e., maintain real power
output at pre-disturbance levels and
provide voltage and frequency support
consistent with Reliability Standard
PRC–024–3 (Frequency and Voltage
Protection Settings for Generating
Resources).28
13. IBRs across the Bulk-Power
System exhibit common mode failures
that are amplified when IBRs act in the
25 See, e.g., NERC, 2021 Long Term Reliability
Assessment Report, 6 (Dec. 2021), https://
www.nerc.com/pa/RAPA/ra/
Reliability%20Assessments%20DL/NERC_LTRA_
2021.pdf (2021 LTRA Report) (‘‘IBRs respond to
disturbances and dynamic conditions based on
programmed logic and inverter controls, not
mechanical characteristics.’’); see also generally,
Denholm et al., National Renewable Energy
Laboratory, Inertia and the Power Grid: A Guide
Without the Spin, NREL/TP–6120–73856, v (May
2020), https://www.nrel.gov/docs/fy20osti/
73856.pdf.
26 NERC and WECC, San Fernando Disturbance,
2 (Nov. 2020), https://www.nerc.com/pa/rrm/ea/
Documents/San_Fernando_Disturbance_Report.pdf
(San Fernando Disturbance Report) (covering the
San Fernando event (July 7, 2020)).
27 See Essential Reliability Servs. & the Evolving
Bulk-Power Sys. Primary Frequency Response,
Order No. 842, 162 FERC ¶ 61,128, at P 19 (2018)
(describing NERC’s comment that increased IBR
deployment alongside retirement of synchronous
generation resources has contributed to the decline
in primary frequency response); see also NERC, Fast
Frequency Response Concepts and Bulk Power
System Reliability Needs, 5 (Mar. 2020), https://
www.nerc.com/comm/PC/
InverterBased%20Resource
%20Performance%20Task%20Force%20IRPT/
Fast_Frequency_Response_Concepts_and_BPS_
Reliability_Needs_White_Paper.pdf (Fast Frequency
Response White Paper) (explaining that as the
instantaneous penetration of IBRs with little or no
inertia continues to increase, system rate of change
of frequency after a loss of generation will increase
and the time available to deliver frequency
responsive reserves will shorten, and illustrating
the steeper rate of change of frequency and the
importance of speed of response).
28 The NOPR referred to Reliability Standard
PRC–024–2; however, Reliability Standard PRC–
024–3 became mandatory and enforceable on
October 1, 2022. Reliability Standards applicable in
the United States, both effective and retired, are
available at https://www.nerc.com/pa/Stand/Pages/
USRelStand.aspx.

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aggregate.29 Thus, both localized and
interconnection-wide IBR issues must
be identified, studied, and mitigated to
preserve Bulk-Power System
reliability.30 Although IBRs are typically
smaller-megawatt (MW) facilities, they
are at greater risk than synchronous
generation resources of ceasing to
provide power to the Bulk-Power
System in response to a single fault on
the transmission or sub-transmission
systems. Specifically, such response can
occur when individual IBR controls and
equipment protection settings are not
configured to ride through system
disturbances.31 IBRs that enter
momentary cessation may act in
aggregate and cause a reduction in
power output far in excess of any
individual IBR’s impact on the BulkPower System. The potential impact of
IBRs is not restricted by the size of a
single facility or an individual balancing
authority area, but by the number of
IBRs or percent of generation made up
by IBRs within a region. In areas of high
IBR penetration, this type of aggregate
response may have an impact much
greater than the most severe single
contingency (i.e., the traditional worstcase N–1 contingency) 32 of a balancing
authority area, potentially adversely
affecting other balancing authority areas
within an interconnection.33 Unless
29 NERC, An Introduction to Inverter-Based
Resources on the Bulk-Power System, 6 (June 2023),
https://www.nerc.com/pa/Documents/2023_NERC_
Guide_Inverter-Based-Resources.pdf (explaining
that ‘‘NERC continues to analyze large-scale grid
disturbances involving common mode failures in
inverter-based resources that, if not addressed,
could lead to catastrophic events in the future’’).
30 See NOPR, 181 FERC ¶ 61,125 at P 4.
31 See, e.g., NERC and WECC, 900 MW Fault
Induced Solar Photovoltaic Resource Interruption
Disturbance Report, 19 (Feb. 2018), https://
www.nerc.com/pa/rrm/ea/
October%209%202017%20Canyon%202
%20Fire%20Disturbance%20Report/
900%20MW%20Solar%20Photovoltaic
%20Resource%20Interruption%20
Disturbance%20Report.pdf (Canyon 2 Fire Event
Report) (covering the Canyon 2 Fire event (October
9, 2017)) (finding momentary cessation as a major
cause for the loss of IBRs when voltages rose above
1.1 per unit or decreased below 0.9 per unit).
32 The most severe single contingency, or the N–
1 contingency, generally refers to the concept that
a system must be able to withstand an unexpected
failure or outage of a single system component and
maintain reliable service at all times. See, e.g.,
NERC, Glossary of Terms Used in NERC Reliability
Standards, 17 (Mar. 8, 2023), https://
www.nerc.com/pa/Stand/
Glossary%20of%20Terms/Glossary_of_Terms.pdf
(NERC Glossary) (defining ‘‘most severe single
contingency’’).
33 See, e.g., San Fernando Disturbance Report at
vi (stating that ‘‘[t]his event, as with past events,
involved a significant number of solar PV resources
reducing power output (either due to momentary
cessation or inverter tripping) as a result of
normally-cleared [Bulk-Power System] faults. The
widespread nature of power reduction across many

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IBRs are configured and programmed to
ride through normally cleared
transmission faults, the potential impact
of losing IBRs individually or in the
aggregate will continue to increase as
IBRs are added to the Bulk-Power
System and make up an increasing
proportion of the resource mix.
14. Simulations conducted by the
NERC Resource Subcommittee
demonstrate that the risks to BulkPower System reliability posed by
momentary cessation are greater than
any of the actual IBR disturbances that
NERC has documented since 2016.34
These simulations indicate the potential
for: (1) normally-cleared, three-phase
faults at certain locations in the Western
Interconnection to result in upwards of
9,000 MW of solar PV IBRs entering
momentary cessation across a large
geographic region; (2) transient
instability caused by excessive transfer
of inter-area power flows during and
after momentary cessation; and (3) a
drop in frequency that falls below the
first stage of under frequency load
shedding in the Western Electricity
Coordinating Council (WECC) region
(traditionally studied as the loss of the
two Palo Verde nuclear units in
Arizona, which total approximately
2,600 MW). These simulation results
indicate that IBR momentary cessation
occurring in the aggregate can lead to
instability, system-wide uncontrolled
separation, and voltage collapse.35
15. Although IBRs present risks that
Bulk-Power System planners and
operators must account for, IBRs also
present new opportunities to support
the grid and respond to abnormal grid
conditions.36 When appropriately
programmed, IBRs can operate during
greater frequency deviations (i.e., a
wider frequency range) than
synchronous generation resources.37
This operational flexibility—and the
ability of IBRs to perform with
precision, speed, and control—could
mitigate disturbances on the Bulk-Power
System. For Bulk-Power System
operators to harness the unique
performance and control capabilities of
IBRs, these resources must be properly
configured and programmed to support
facilities poses risks to [Bulk-Power System]
performance and reliability.’’).
34 See NERC, Resource Loss Protection Criteria
Assessment, (Feb. 2018), https://www.nerc.com/
comm/PC/InverterBased%20
Resource%20Performance%20Task
%20Force%20IRPT/IRPTF_RLPC_Assessment.pdf.
35 Id. at 1–2, key findings 4, 7, 8.
36 See, e.g., IBR Performance Guideline at vii
(finding that the power electronics aspects of IBRs
‘‘present new opportunities in terms of grid control
and response to abnormal grid conditions.’’).
37 See, e.g., Fast Frequency Response White Paper
at 11.

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grid voltage and frequency during
normal and abnormal grid conditions
and must be accurately modeled and
represented in transmission planning
and operations models.
C. Notice of Proposed Rulemaking
16. On November 17, 2022, the
Commission issued the NOPR in this
proceeding, proposing to direct NERC to
submit new or modified Reliability
Standards addressing four gaps in the
currently effective Reliability Standards
pertaining to IBRs: (1) data sharing; (2)
model validation; (3) planning and
operational studies; and (4) performance
requirements.38 The Commission
initiated this action in light of the rapid
change in the generation resource mix
currently underway on the Bulk-Power
System and the projected addition of
unprecedented numbers of IBRs to the
Bulk-Power System.39 The Commission
noted that IBRs provide many benefits,
but that IBRs also present new
considerations for transmission
planning and operation of the BulkPower System.40
17. The Commission proposed to
direct NERC to address the four
reliability gaps by developing one or
more new Reliability Standards or
modifying the currently effective
Reliability Standards. The Commission
did not propose specific requirements;
instead, the Commission identified
concerns that the Reliability Standards
should address. The Commission sought
comments on its identified concerns
and whether there were other concerns
related to planning for and integrating
IBRs that the Commission should direct
NERC to address in this or a future
proceeding.41
18. First, the Commission proposed to
direct NERC to develop new or modified
Reliability Standards addressing IBR
data sharing. The Commission proposed
that the new or modified Reliability
Standards should ensure that NERC
registered entities 42 have the necessary
data to predict the behavior of all IBRs,
including registered and unregistered
IBRs individually and in the aggregate,
and IBR–DERs in the aggregate, and
their impact on the reliable operation of
38 NOPR,
39 Id.

181 FERC ¶ 61,125 at P 1.
P 2 (citing 2020 LTRA Report).

40 Id.
41 Id.

P 6.
identifies and registers Bulk-Power
System users, owners, and operators who are
responsible for performing specified reliability
functions to which requirements of mandatory
Reliability Standards are applicable. See NERC,
Rules of Procedure, Section 500 (Organization
Registration and Certification) (Aug. 25, 2022),
https://www.nerc.com/AboutNERC/
RulesOfProcedure/NERC%20ROP%20
effective%2020220825_with%20appendicies.pdf.
42 NERC

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the Bulk-Power System. The
Commission stated that the new or
modified Reliability Standards should
ensure that generator owners,
transmission owners, and distribution
providers are required to share validated
modeling, planning, operations, and
disturbance monitoring data for
registered and unregistered IBRs and
IBR–DERs in the aggregate with
planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities.43
19. Second, the Commission proposed
to direct NERC to develop new or
modified Reliability Standards
addressing IBR model validation. The
Commission proposed that the new or
modified Reliability Standards should
ensure that IBR models are
comprehensive, validated, and updated
in a timely manner, so that they can
adequately predict the behavior of
registered and unregistered IBRs
individually and in the aggregate, and
IBR–DERs in the aggregate, and their
impacts on the reliable operation of the
Bulk-Power System.44
20. Third, the Commission proposed
to direct NERC to develop new or
modified Reliability Standards
addressing IBR planning and
operational studies. The Commission
proposed to direct that the new or
modified Reliability Standards ensure
that validated IBR models are included
in transmission planning and
operational studies to assess the
reliability impacts on Bulk-Power
System performance by registered and
unregistered IBRs individually and in
the aggregate, as well as IBR–DERs in
the aggregate. The Commission stated
that the Reliability Standards should
ensure that planning and operational
studies assess the impacts of registered
and unregistered IBRs individually and
in the aggregate, and IBR–DERs in the
aggregate, within and across planning
and operational boundaries for normal
operations and contingency event
conditions.45
21. Fourth, the Commission proposed
to direct NERC to develop new or
modified Reliability Standards
addressing IBR performance
requirements.46 The Commission
explained that the new or modified
Reliability Standards should require
that registered IBRs provide frequency
and voltage support during frequency
and voltage excursions, including postdisturbance ramp rates and phase lock
43 NOPR,

181 FERC ¶ 61,125 at P 5.

44 Id.
45 Id.
46 Id.

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loop synchronization, in a manner
necessary to contribute toward meeting
the overall system needs for essential
reliability services.47 Further, the
Commission stated that the new or
modified Reliability Standards should
establish clear and reliable technical
limits and capabilities for registered
IBRs to ensure that all registered IBRs
are operated in a predictable and
reliable manner during both normal
operations and contingency event
conditions.
22. Finally, the Commission proposed
to direct NERC to submit a compliance
filing within 90 days of the effective
date of the final action in this
proceeding. The Commission proposed
to direct NERC to include in its
compliance filing a detailed,
comprehensive standards development
and implementation plan explaining
how NERC will prioritize the
development and implementation of
new or modified Reliability Standards.
The Commission stated that NERC
should explain how it would prioritize
its IBR Reliability Standard projects to
meet the directives in the final action,
taking into account the risk posed to the
reliability of the Bulk-Power System,
standard development projects already
underway, resource constraints, and
other factors if necessary.48
23. The comment period for the NOPR
ended on February 6, 2023, with reply
comments due on March 6, 2023. The
Commission received 18 initial
comments and 3 reply comments.49
III. Need for Reform
24. As the Commission explained in
the NOPR, a number of events have
demonstrated the challenges to
transmission planning and operations of
the Bulk-Power System posed by gaps in
the Reliability Standards specific to
IBRs.50 In this final action, we continue
to find that as the resource mix trends
towards higher penetrations of IBRs, the
need to reliably integrate these
resources into the Bulk-Power System is
expected to grow, and that the currently
effective Reliability Standards do not
adequately address IBR reliability

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47 Id.

(citing Essential Reliability Services
Concept Paper at vi).
48 Id. P 7.
49 A list of commenters to the NOPR and the
abbreviated names used in this final action appear
in Appendix A. Interventions are not necessary to
file comments in a rulemaking. Nevertheless,
Acciona Energy USA Global LLC, Cordelio USA,
Inc., Electricity Consumers Resource Council, the
Federal Energy Advocate, the Public Utilities
Commission of Ohio, Georgia Transmission
Corporation, GlidePath Development, LLC,
Monitoring Analytics, LLC, and Old Dominion
Electric Cooperative filed motions to intervene.
50 See NOPR, 181 FERC ¶ 61,125 at PP 24–26.

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risks.51 The continuing risks that the
increasing penetration of IBRs pose to
the reliable operation of the Bulk-Power
System underscore the need for
mandatory Reliability Standards to
address these issues on a nationwide
basis.
25. NERC, groups such as the Institute
of Electrical and Electronics Engineers
(IEEE), and other entities have
attempted to address IBR-related
reliability concerns at the manufacturer,
state, local, or individual entity level
over the past several years.52 While the
various ongoing IBR-related projects are
important efforts, the absence of a
comprehensive plan to require that the
increasing numbers of IBRs are reliably
interconnected, planned for, and
operated on the Bulk-Power System
limits those individual projects’ overall
impact. Moreover, these individual
efforts could lead to inconsistent results
that fail to fully address the gaps
identified herein, a concern that could
be resolved by addressing all IBR issues
through the Reliability Standards.
Therefore, to help ensure that a broader
range of reliability concerns related to
the impacts of IBRs on the Bulk-Power
System are addressed, that any
necessary new requirements apply
nationwide, and that any new rules are
mandatory, we find that it is imperative
for NERC to develop new or modified
Reliability Standards as directed in this
final action to address reliability
concerns related to IBRs at all stages of
interconnection, planning, and
operations. However, we note that the
directives to NERC in this final action
are intended to complement other
ongoing NERC and Commission actions
to address the impacts of all IBRs on the
Bulk-Power System, as well as existing
voluntary efforts underway, and are not
intended to supersede or interfere with
these efforts.
A. Current Actions Are Insufficient To
Address IBR Reliability Risks
26. As explained in the NOPR, at least
12 documented events on the BulkPower System 53 show IBRs acting
51 Id.

PP 26–27.
example, to address gaps in data and model
validation and to facilitate sharing and combining
of neighboring planning models, ISO New England
(ISO–NE) has taken steps to retire obsolete and
unapproved models within its own footprint. See
ISO–NE, Generator Data Submittal Requirements—
Planning, Topic Retiring Obsolete and NERC NonApproved Models, 121–125 (Jan. 24, 2023), https://
www.iso-ne.com/static-assets/documents/2023/01/
20230124-gen-data-submittal-requirementsplanning.pdf.
53 The 12 events report an average of
approximately 1,000 MW of IBRs entering into
momentary cessation or tripping in the aggregate.
The 12 Bulk-Power System events are: (1) the Blue
Cut Fire (August 16, 2016); (2) the Canyon 2 Fire
52 For

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74255

unexpectedly and adversely in response
to normally cleared transmission line
faults on the Bulk-Power System, each
highlighting one or more common mode
failures of IBRs of various sizes and
voltage connection levels.54
27. In addition to those 12
documented events discussed in the
NOPR, on June 4, 2022, an IBR-related
disturbance near Odessa, Texas (the
third in this location) occurred. During
this disturbance, a normally cleared
single-line-to-ground fault resulted in a
total loss of 2,555 MW of synchronous
and IBR generation, and system
frequency dropped to 59.7 Hz.55 This is
the largest (to date) NERC-recorded IBRrelated disturbance event and the total
loss of generation resources was one and
half times larger than the average loss of
the 12 preceding reported events. The
NERC and Texas Reliability Entity, Inc.
(Texas RE) joint report, issued in
December 2022, explains that this event
is significant because the size of this
disturbance nearly exceeded the Texas
Interconnection Resource Loss
Protection Criteria (i.e., 2,750 MW)
defined in Reliability Standard BAL–
003–2,56 which is used to establish the
largest credible contingency for
frequency stability in an
interconnection.57
(October 9, 2017); (3) Angeles Forest (April 20,
2018); (4) Palmdale Roost (May 11, 2018); (5) San
Fernando (July 7, 2020); (6) the first Odessa, Texas
event (May 9, 2021); (7) the second Odessa, Texas
event (June 26, 2021); (8) Victorville (June 24,
2021); (9) Tumbleweed (July 4, 2021); (10) Windhub
(July 28, 2021); (11) Lytle Creek (August 26, 2021);
and (12) Panhandle Wind Disturbance (March 22,
2022).
54 NOPR, 181 FERC ¶ 61,125 at P 4.
55 A power system deviating from 60 Hz indicates
there is a generation and load imbalance. When the
generation loss is too large, automatic underfrequency load shedding is used to rebalance the
power system to prevent cascading failures that
lead to blackouts. In Texas, the automatic underfrequency load shed (UFLS) program is set to trigger
a sudden loss of load at 59.3 Hz. See generally
Public Utility Commission of Texas, Load Shed
Protocols for the Electric Reliability Council of
Texas (ERCOT) Region, (Aug. 31, 2022), https://
ftp.puc.texas.gov/public/puct-info/agency/
resources/reports/leg/PUC_Load_Shed_Protocols_
Study.pdf. See also NERC Newsroom
Announcement Odessa Disturbance Illustrates
Need for Immediate Industry Action on InverterBased Resources (Dec. 8, 2022), https://
www.nerc.com/news/Headlines%20DL/
OdessaDisturbance_08DEC22.pdf (explaining that
‘‘[t]he 2022 Odessa disturbance was a Category 3a
event in the NERC Event Analysis Process, and the
combined loss of generation nearly exceeded the
Texas Interconnection Resource Loss Protection
Criteria.’’).
56 See Reliability Standard BAL–003–2
(Frequency Response and Frequency Bias Setting),
attach. A.
57 NERC and Texas RE, 2022 Odessa Disturbance,
v (Dec. 2022), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/NERC_2022_Odessa_
Disturbance_Report%20(1).pdf (Odessa 2022

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28. In response to the multiple
Odessa, Texas disturbances, NERC
issued its third level 2 alert on IBR
performance issues on March 14,
2023.58 In the alert, NERC states its level
2 alert is necessary because the
disturbances in Odessa, Texas, showed
that solar PV IBR resources exhibited
‘‘systemic performance issues’’ with the
potential to cause widespread outages
on the Bulk-Power System.59 Although
the NERC alert pertains specifically to
solar PV resources, the alert
recommendations may be applicable to
Bulk-Power System connected battery
energy storage systems. Further, NERC
explains that as the penetration of BulkPower System-connected IBRs
increases, it will be necessary to address
performance deficiencies in an
‘‘effective and efficient manner.’’ 60 In
the March 2023 Alert, NERC sought to
gather information from registered
generator owners of solar-PV (i.e., IBRs)
and to encourage them to implement
recommendations to: (1) ensure inverter
protection settings, collector system
settings, and substation settings are
updated or changed to mitigate
inadvertent operations; and (2) ensure
that facility control modes, fault ride
through modes and parameters, and
protections are set and coordinated to
facilitate Bulk-Power System voltage
and frequency ride through.61
29. NERC also recently issued another
disturbance report covering events in
Southwest Utah in the morning of April
10, 2023.62 NERC explains that the
causes of the Southwest Utah
disturbance are similar to past solar PV
IBR-related events.63 NERC identifies
this event as the ‘‘first major widespread
solar [PV] loss to occur in the Western
Interconnection outside of
California.’’ 64
30. NERC has found that distributed
energy resources’ (i.e., IBR–DERs’)
responses to Bulk-Power-System
Disturbance Report) (covering events in Odessa,
Texas on June 4, 2022).
58 NERC, Industry Recommendation: InverterBased Resource Performance Issues (Mar. 2023),
https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/
NERC%20Alert%20R-2023-03-1401%20Level%202%20-%20InverterBased%20Resource%20Performance%20Issues.pdf
(March 2023 Alert).
59 See NOPR, 181 FERC ¶ 61,125 at P 18
(explaining that the level 2 alerts recommend
specific voluntary action to be taken by registered
IBRs).
60 March 2023 Alert at 1.
61 Id.
62 NERC and WECC, 2023 Southwest Utah
Disturbance (Aug. 2023), https://www.nerc.com/
comm/RSTC_Reliability_Guidelines/NERC_2023_
Southwest_UT_Disturbance_Report.pdf (Southwest
Utah Disturbance Report).
63 Id. at iv.
64 Id.

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disturbances can cause short term net
load increases likely attributed to
aggregate IBR–DERs tripping.65 This
behavior and the resulting net load
increases can impact Bulk-PowerSystem performance.66
31. NERC has also issued two recent
IBR-related Reliability Guidelines. In
February 2023 NERC issued an updated
guideline on aggregate DER modeling
(DER_A model),67 and in March 2023,
NERC issued its first guideline on
electromagnetic transient (EMT)
modeling and studies for IBRs.68
32. NERC also has nine separate
projects underway to update its
currently effective Reliability Standards
relevant to IBRs; however, these projects
are still in their early stages and, even
if they are completed, the results of
these efforts may not fully address the
reliability risks that IBRs pose to the
Bulk-Power System described above.69
65 Multiple Solar PV Disturbances in CAISO:
Disturbances between June and August 2021 Joint
NERC and WECC Staff Report, 17–18, (Apr. 2022),
https://www.nerc.com/pa/rrm/ea/Documents/
NERC_2021_California_Solar_PV_Disturbances_
Report.pdf.
66 San Fernando Disturbance: Southern California
Event: July 7, 2020 Joint NERC and WECC Staff
Report, 12 (Nov. 2020), https://www.nerc.com/pa/
rrm/ea/Documents/San_Fernando_Disturbance_
Report.pdf.
67 NERC, Reliability Guideline: Parameterization
of the DER_A Model for Aggregate DER (Feb. 2023),
https://www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline_ModelingMerge_
Responses_clean.pdf (2023 DER_A Model
Guideline). The DER_A model is the approved
steady state and dynamic model that industry has
validated and maintained to model IBR–DERs in the
aggregate and used to study the potential impacts
of IBR–DERs in the aggregate on the Bulk-Power
System. The term ‘‘parameterize’’ means to adjust
the parameter values of a generic model to best
reflect the dynamic characteristics of a user-defined
model. The parameterization process aims at
reducing the difference (error) between the dynamic
responses of both the generic and user-defined
models. See, e.g., Energy Systems Integration
Group, Parameterization, https://www.esig.energy/
wiki-main-page/parameterization-d1/.
68 NERC, Reliability Guideline: Electromagnetic
Transient Modeling for BPS-Connected InverterBased Resources—Recommended Model
Requirements and Verification Practices (Mar.
2023), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline-EMT_
Modeling_and_Simulations.pdf (EMT Modeling
Guideline).
69 The current NERC standards development
projects underway include: (1) Project 2021–04
(Modifications to PRC–002–2) to ensure that
disturbance monitoring data is available and
provided by generator owners of IBR facilities; (2)
Project 2020–06 (Verifications of Models and Data
for Generators) to enhance requirements for model
verification; (3) Project 2022–04 (EMT Modeling) to
address the inclusion of EMT modeling and studies
in relevant Reliability Standards; (4) Project 2022–
02 (Modifications to TPL–001–5.1 and MOD–032–
1) addressing certain issues regarding appropriate
inclusion of IBRs and DERs in planning
assessments; (5) Project 2020–02 (Modifications to
PRC–024 (Generator Ride-through)) to revise or
replace current Reliability Standard PRC–024–3
with a standard that will require ride through

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33. While we recognize NERC’s
ongoing efforts, systemic fault ride
through deficiencies continue to result
in IBRs displaying unexpected and
abnormal performance during grid
disturbances.70 In fact, in the March
2023 Alert, NERC states that IBR-related
issues continue to occur and has
announced plans to issue an alert by the
end of 2023 regarding IBR modeling
issues.71
34. The Commission has also been
actively addressing ongoing IBR-related
concerns. Concurrently with the NOPR,
the Commission issued an order
directing NERC to identify and register
owners and operators of unregistered
IBRs that in the aggregate have a
material impact on the reliable
operation of the Bulk-Power System.72
On February 15, 2023, as amended on
March 13, 2023, NERC submitted its
compliance filing, which included its
work plan setting out NERC’s planned
activities and milestones to register
generator owners and operators of IBRs.
On May 18, 2023, the Commission
approved NERC’s work plan and
associated implementation
milestones.73
35. The Commission also recently
revised the pro forma Large Generator
Interconnection Procedures (LGIP), the
pro forma Large Generator
Interconnection Agreement (LGIA), the
pro forma Small Generator
Interconnection Procedures (SGIP), and
the pro forma Small Generator
Interconnection Agreement (SGIA) in
Order No. 2023.74 Some of those
revisions address identified deficiencies
performance from all generation resources; (6)
Project 2023–02 (Performance of IBRs) to address
post-event performance validation ensuring that
resources perform the way they are expected or
required to perform; (7) Project 2021–01
(Modifications to MOD–025 and PRC–019) to
ensure that plant active and reactive power
capabilities are accurately provided to planning
entities for use in studies; (8) Project 2021–02
(Modifications to VAR–002–4.1) to clarify whether
the generator operator of a dispersed power
resource must notify its associated transmission
operator upon a status change of a voltage
controlling device on an individual generating unit;
and (9) Project 2023–01 (EOP–004 IBR Event
Reporting) to ensure timely reporting of events
involving IBRs. See NERC, Reliability Standards
Under Development, https://www.nerc.com/pa/
Stand/Pages/Standards-Under-Development.aspx.
70 March 2023 Alert at 6–7.
71 Id. at 6.
72 See IBR Registration Order, 181 FERC ¶ 61,124
at P 6.
73 N. Am. Elec. Reliability Corp., 183 FERC
¶ 61,116 (2023) (Order Approving Workplan). On
August 16, 2023, NERC submitted its first progress
update on its registration workplan. See NERC,
Filing, Docket No. RD22–4–001 (filed Aug. 16,
2023).
74 See Improvements to Generator
Interconnection Agreements & Procs., Order No.
2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC
¶ 61,054 (2023).

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with respect to IBR modeling and ride
through performance by requiring that
newly interconnecting non-synchronous
generators (i.e., IBRs) (1) submit
accurate and verified models with a
comparable level of accuracy as
synchronous generation resources and
(2) configure or set control and
protection settings to ride through
disturbances and continue to support
system reliability during abnormal
frequency conditions and voltage
conditions within any physical
limitations of the generating facility.75
36. In addition to NERC and
Commission efforts, there are several
voluntary industry standards and
manufacturer certification efforts related
to IBRs, such as the IEEE standard
2800–2022 76 for transmission
connected IBRs and IEEE standard
1547–2018 77 and Underwriters
Laboratory (UL) standard UL 1741 78 for
distributed energy resources. These
efforts are intended to enhance the
operating performance and control
capabilities of IBRs; however, these
efforts do not apply to all relevant IBRs
and require adoption by state or other
regulatory authorities to become
mandatory and enforceable.79
75 Id.

PP 1661, 1715.
Standard for Interconnection and
Interoperability of Inverter-Based Resources (IBR)
Interconnecting with Associated Transmission
Electric Power Systems (Apr. 22, 2022), https://
standards.ieee.org/ieee/2800/10453/ (IEEE 2800–
2022) (establishing uniform technical minimum
requirements for the interconnection, capability,
and performance of IBRs for reliable integration
onto the Bulk-Power System).
77 IEEE, Interconnection and Interoperability of
Distributed Energy Resources with Associated
Electric Power Systems Interfaces (Feb. 15, 2018),
https://standards.ieee.org/ieee/1547/5915/ (IEEE
1547–2018). The IEEE 1547–2018 and more recent
2020 amendment (IEEE 1547a–2020) of this
standard enhance operating performance and
control capabilities of IBR–DERs. For example, IBR–
DERs compliant with the IEEE standard will be
equipped with the capability to ride through voltage
and frequency fluctuations in support of the reliable
operation of the Bulk-Power System.
78 UL Standard 1741 Edition 3, Inverters,
Converters, Controllers and Interconnection System
Equipment for Use with Distributed Energy
Resources Scope, https://
www.shopulstandards.com/
ProductDetail.aspx?UniqueKey=40673.
79 The IEEE Standards Association’s board
approved IEEE–2800–2022 in September 2022. See
IEEE, IEEE Standard for Interconnection and
Interoperability of Inverter-Based Resources (IBRs)
Interconnecting with Associated Transmission
Electric Power Systems, https://standards.ieee.org/
ieee/2800/10453/ (explaining that IEEE–2800–2022
establishes uniform technical minimum
requirements for the interconnection, capability,
and lifetime performance of IBRs interconnecting
with transmission and sub-transmission systems in
North America). For IEEE–1547, states have made
varied progress in adopting the standard. See IEEE,
IEEE Standard for Interconnection and
Interoperability of Distributed Energy Resources
with Associated Electric Power Systems Interfaces,
https://sagroups.ieee.org/scc21/standards/1547rev/;

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B. Existing Reliability Standards Do Not
Adequately Address IBR Reliability
Risks
1. Data Sharing
37. The currently effective Reliability
Standards do not require owners and/or
operators of registered IBRs,
transmission owners that have
unregistered IBRs on their systems, or
distribution providers that have IBR–
DERs on their systems to provide
planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities with data that accurately
represents IBRs. Examples of needed
data may include location; capacity;
telemetry; steady-state, dynamic, and
short circuit modeling information;
control settings; ramp rates; equipment
status; and disturbance analysis data.80
Data that accurately represents IBRs is
necessary to properly plan for, operate,
and analyze IBR performance on the
Bulk-Power System.81 Without data that
accurately represents all IBRs, planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities are
not able to develop system models that
accurately account for the behavior of
IBRs on their system, nor are they able
to facilitate the analysis of Bulk-Power
System disturbances.82
38. While Reliability Standard MOD–
032–1 (Data for Power System Modeling
and Analysis), Requirement R2 requires
generator owners to submit modeling
see also Odessa 2022 Disturbance Report at v
(explaining that the 2022 Odessa Disturbance ‘‘is a
perfect illustration of the need for immediate
industry action to ensure reliable operation of the
[Bulk-Power System] with increasing penetrations
of inverter-based resources.’’).
80 NOPR, 181 FERC ¶ 61,125 at P 27.
81 NERC has provided examples of necessary
planning and operational IBR data. See, e.g., NERC,
Industry Recommendation: Loss of Solar Resources
during Transmission Disturbances due to Inverter
Settings—II, 7–8 (May 2018), https://
www.nerc.com/pa/rrm/bpsa/Alerts%20DL/NERC_
Alert_Loss_of_Solar_Resources_during_
Transmission_Disturbance-II_2018.pdf (Loss of
Solar Resources Alert II) (describing examples of
planning and operational IBR data); NERC and
Texas RE, Odessa Disturbance, 20–21 (Sept. 2021),
https://www.nerc.com/pa/rrm/ea/Documents/
Odessa_Disturbance_Report.pdf (Odessa 2021
Disturbance Report) (covering events in Odessa,
Texas on May 9, 2021 and June 26, 2021); see
generally NERC and WECC, WECC Base Case
Review: Inverter-Based Resources (Aug. 2020),
https://www.nerc.com/comm/PC/InverterBased%
20Resource%20Performance%20Task%20Force%
20IRPT/NERC-WECC_2020_IBR_Modeling_
Report.pdf (Western Interconnection Base Case IBR
Review); NERC, Reliability Guideline: DER Data
Collection for Modeling in Transmission Planning
Studies (Sept. 2020), https://www.nerc.com/comm/
RSTC_Reliability_Guidelines/Reliability_Guideline_
DER_Data_Collection_for_Modeling.pdf (IBR–DER
Data Collection Guideline).
82 NOPR, 181 FERC ¶ 61,125 at P 28.

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data and parameters to their
transmission planners and planning
coordinators, it does not require
generator owners to submit registered
IBR-specific modeling data and
parameters such as control settings for
momentary cessation and ramp rates,
which are necessary for modeling steady
state and dynamic registered IBR
performance for purposes of planning
the Bulk-Power System.83 Nor does
Reliability Standard TOP–003–5
(Operational Reliability Data) require
generator owners to submit such
registered IBR-specific modeling data
and parameters to their transmission
operators or balancing authorities.84
39. Moreover, the currently effective
Reliability Standards do not ensure that
Bulk-Power System planners and
operators receive disturbance
monitoring data regarding all generation
resources capable of having a material
impact on the reliable operation of the
Bulk-Power System, including
registered IBRs. Such data is needed to
adequately assess disturbance events
(e.g., a fault on the line) and the
behavior of IBRs during those events.
Without adequate monitoring capability,
the disturbance analysis data for a
system event is insufficient to
effectively determine the causes of the
system event.85
40. Limitations on the availability of
event data have hampered efforts by
NERC, stakeholders, and industry to
determine the causes of various events
since 2016. In many instances, data
were limited and disturbance
monitoring equipment was absent
because registered IBRs interconnected
at lower voltages and fell below the
83 See NERC, Technical Report, BPS-Connected
Inverter-Based Resource Modeling and Studies, 35
(May 2020), https://www.nerc.com/comm/PC/
InverterBased%20Resource%20Performance%20
Task%20Force%20IRPT/IRPTF&_IBR_Modeling_
and_Studies_Report.pdf (Modeling and Studies
Report) (stating that Reliability Standard MOD–
032–1 ‘‘does not prescribe the details that the
modeling requirements must cover; rather, the
standard requirements leave the level of detail and
data formats up to each [transmission planner] and
[planning coordinator] to define.’’) (footnote
omitted).
84 See NOPR, 181 FERC ¶ 61,125 at P 29 (referring
to Reliability Standard TOP–003–4, the version of
the standard enforceable at that time. Reliability
Standard TOP–003–5 became mandatory and
enforceable on April 1, 2023).
85 NERC and WECC, Multiple Solar PV
Disturbances in CAISO, 13 (Apr. 2022), https://
www.nerc.com/pa/rrm/ea/Documents/NERC_2021_
California_Solar_PV_Disturbances_Report.pdf
(2021 Solar PV Disturbances Report) (covering four
events: Victorville (June 24, 2021); Tumbleweed
(July 4, 2021); Windhub (July 28, 2021); and Lytle
Creek (August 26, 2021)) (explaining that the
‘‘analysis team had significant difficulty gathering
useful information for root cause analysis at
multiple facilities . . . [and] this led to an
abnormally large number of ‘unknown’ causes of
power reduction for the plants analyzed’’).

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MVA threshold.86 These IBRs therefore
did not fall within the thresholds of the
currently effective Reliability Standard
PRC–002–2 (Disturbance Monitoring
and Reporting Requirements)
Attachment 1 requirements for
equipment installation.87 Further, the
absence of adequate monitoring
capability leads to the potential for
unreliable operation of generation
resources due to the inability to
effectively gather disturbance analysis
data and develop mitigation strategies to
either avoid or recover from abnormal
resource performance during
disturbance events in the future. While
Reliability Standard PRC–002–2
requires the installation of disturbance
monitoring equipment at certain key
nodes (e.g., stability limited interfaces),
and such limited placements have been
adequate to provide the data necessary
to analyze major system events in the
past, NERC has found that the existing
disturbance monitoring equipment is
not sufficient (e.g., lack of high speed
data captured at the IBR or plant level
controller and low resolution time
stamping of inverter sequence of event
recorder information) to analyze the
widespread system events that have
become more common since 2016.88
86 NERC, Improvements to Interconnection
Requirements for BPS-Connected Inverter-Based
Resources, at 1 (Sept. 2019) (IBR Interconnection
Requirements Guideline) (reporting that the
majority of newly interconnecting IBRs are either
connecting at voltages less than 100 kV or with
capacity less than 75 MVA and therefore do not
meet the size criteria in the bulk electric system
definition). NERC’s Commission-approved bulk
electric system definition is a subset of the BulkPower System and defines the scope of the
Reliability Standards and the entities subject to
NERC compliance. Revisions to Electric Reliability
Org. Definition of Bulk Elec. Sys. & Rules of Proc.,
Order No. 773, 141 FERC ¶ 61,236 (2012) order on
reh’g, Order No. 773–A (May 17, 2013), 143 FERC
¶ 61,053 (2013), rev’d sub nom. People of the State
of N.Y. v. FERC, 783 F.3d 946 (2d Cir. 2015); NERC
Glossary at 7–9.
87 NOPR, 181 FERC ¶ 61,125 at P 32; see also
Reliability Standard PRC–002–2, Requirement
R5.1.1 (specifying dynamic disturbance recording
data for generation resource(s) with gross individual
nameplate rating greater than or equal to 500 MVA,
and gross individual nameplate rating greater than
or equal to 300 MVA where the gross plant/facility
aggregate nameplate rating is greater than or equal
to 1,000 MVA).
88 See NOPR, 181 FERC ¶ 61,125 at P 32 n.74
(citing NERC and WECC, April and May 2018 Fault
Induced Solar Photovoltaic Resource Interruption
Disturbances Report, 23 (Jan. 2019), https://
www.nerc.com/pa/rrm/ea/April_May_2018_Fault_
Induced_Solar_PV_Resource_Int/April_May_2018_
Solar_PV_Disturbance_Report.pdf (Angeles Forest
and Palmdale Roost Events Report) (covering the
Angeles Forest (April 20, 2018) and Palmdale Roost
(May 11, 2018) events and explaining that the
‘‘widespread nature of power reduction across
many facilities poses risks to [Bulk-Power System]
performance and reliability’’ and finding that the
‘‘lack of available high-speed data at multiple
inverter-based resources has hindered event
analysis’’); San Fernando Disturbance Report at 7;

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41. The currently effective Reliability
Standards do not require Bulk-Power
System planners and operators to
receive modeling data and parameters
regarding unregistered IBRs that,
individually or in the aggregate, are
capable of adversely affecting the
reliable operation of the Bulk-Power
System. Further, the currently effective
Reliability Standards do not require that
Bulk-Power System planners and
operators receive modeling data and
parameters that accurately represent
IBR–DERs that in the aggregate have a
material impact on the reliable
operation of the Bulk-Power System.89
As shown by various reports and
guidelines,90 Bulk-Power System
planners and operators do not currently
have the data to accurately model the
behavior of registered and unregistered
IBRs individually and in the aggregate,
and IBR–DERs in the aggregate, for
steady-state, dynamic, and short circuit
studies.
2. Data and Model Validation
42. Bulk-Power System planners and
operators need accurate planning,
operations, and interconnection-wide
models to ensure the reliable operation
of the Bulk-Power System. Bulk-Power
System planners and operators use
Odessa 2021 Disturbance Report at 11; NERC,
Odessa Disturbance Follow-up White Paper (Oct.
2021), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/White_Paper_Odessa_
Disturbance_Follow-Up.pdf (Odessa Disturbance
White Paper)).
89 See NOPR, 181 FERC ¶ 61,125 at P 80 (stating
that distribution providers should be permitted to
provide IBR–DER modeling data and parameters ‘‘in
the aggregate or equivalent for IBR–DERs
interconnected to their distribution systems (e.g.,
IBR–DERs in the aggregate and modeled by resource
type such as wind or solar PV, or IBR–DERs in the
aggregate and modeled by interconnection
requirements performance to represent different
steady-state and dynamic behavior.’’); see also id.
n.159 (explaining that for IBR–DERs ‘‘a certain
degree of simplification may be needed either by
model aggregation (i.e., clustering of models with
similar performance), by derivation of equivalent
models (i.e., reduced-order representation), or by a
combination of the two.’’).
90 See, e.g., Commission Staff, Distributed Energy
Resources Technical Considerations for the Bulk
Power System Staff Report, Docket No. AD18–10–
000, 11–13 (filed Feb. 15, 2018) (Commission Staff
IBR–DER Reliability Report) (explaining that, absent
adequate data, many Bulk-Power System models
and operating tools will not fully represent the
effects of IBR–DERs in aggregate); see also IBR–DER
Data Collection Guideline at 2 (recommending that
transmission planners and planning coordinators
update their data reporting requirements for
Reliability Standard MOD–032–1, Requirement R1
to explicitly describe the requirements for aggregate
IBR–DER data in a manner that is clear and
consistent with their modeling practices. The IBR–
DER Data Collection Guideline also recommended
that transmission planners and planning
coordinators establish modeling data requirements
for steady-state IBR–DERs in aggregate and
coordinate with their distribution providers to
develop these requirements.).

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electrical component models to build
the generation, transmission, and
distribution facility models that they
combine to build their transmission area
model. These models are further
combined with those of their neighbors
to form the interconnection-wide
models, which are used to analyze the
reliability of the interconnected
transmission system.91 Each of the
planning, operations, and
interconnection-wide models consist
separately of steady state, dynamic, and
short circuit models.
43. Without planning, operations, and
interconnection-wide models that
accurately reflect resource (e.g.,
generation and load) behavior in steady
state and dynamic conditions, BulkPower System planners’ and operators’
system models 92 are unable to
adequately predict resource behavior,
including momentary cessation from
both registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate, and
their subsequent impacts on the BulkPower System.93
44. The currently effective Reliability
Standards do not require the use of
NERC’s approved component models; 94
instead, models are referred to generally
in Reliability Standard MOD–032–1,
Attachment 1.95 Without requirements
to use approved component models in
Bulk-Power System planning and
operations system models, resource
91 See Reliability Standard MOD–033–2 (SteadyState and Dynamic System Model Validation).
92 This final action uses the term ‘‘system
models’’ to refer collectively to planning and
operations transmission area models and
interconnection-wide models.
93 See IBR Interconnection Requirements
Guideline at 24 (stating that a systemic modeling
issue was uncovered regarding the accuracy of the
IBR dynamic models submitted in the
interconnection-wide base cases following the
issuance of the NERC Alert related to the Canyon
2 Fire disturbance).
94 NERC, Libraries of Standardized Powerflow
Parameters and Standardized Dynamics Models
version 1, 1 (Oct. 2015), https://www.nerc.com/
comm/PC/Model%20Validation%20Working%20
Group%20MVWG%202013/NERC%
20Standardized%20Component%20
Model%20Manual.pdf (NERC Standardized
Powerflow Parameters and Dynamics Models)
(explaining that the NERC Modeling Working
Group was tasked to develop, validate, and
maintain a library of standardized component
models and parameters for short-circuit, powerflow,
and dynamics cases. The standardized models in
these libraries have documentation describing their
model structure, parameters, and operation. This
information has been vetted by the industry and
thus deemed appropriate for widespread use in
planning, operations, and interconnection-wide
analysis.).
95 See Reliability Standard MOD–032–1, attach. 1
(explaining that if a user-written model(s) is
submitted in place of a generic or library model, it
must include the characteristics of the model,
including block diagrams, values, and names for all
model parameters, and a list of all state variables).

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owners may provide modeling data that
is based on a user-defined model 96
rather than an approved and industryvetted model.97 The use of user-defined
models in system models can be
problematic because their internal
model components cannot be viewed or
modified, and thus they produce
outputs that cannot be readily explained
or verified.98 Approved generator
models that accurately reflect the
generator behavior in steady state and
dynamic conditions are necessary for
Bulk-Power System planners and
operators to adequately predict IBR
behavior and the subsequent impact of
IBRs on the Bulk-Power System.99
45. Any generation resource model’s
performance must be verified by the
generator owner using real-world data to
confirm that the generation resource
model adequately reflects actual as-built
settings, historic performance, and/or
96 Some commenters use the term ‘‘proprietary’’
to describe user-defined models. For purposes of
this final action, the terms ‘‘proprietary’’ and ‘‘userdefined’’ models are synonymous. A user-defined
model is a unique manufacturer-specific model that
does not appear on the NERC approved component
model list. In Order No. 2023, the Commission
defined a ‘‘user-defined model’’ as any set of
programming code created by equipment
manufacturers or developers that captures the latest
features of controllers that are mainly softwarebased and represents the entities’ control strategies
but does not necessarily correspond to any
particular generic library model. See Order No.
2023, 184 FERC ¶ 61,054 at P 1660.
97 NERC Standardized Powerflow Parameters and
Dynamics Models at 1 (explaining that ‘‘[s]ome of
the model structures have information that is
considered to be proprietary or confidential, which
impedes the free flow of information necessary for
interconnection-wide power system analysis and
model validation.’’); see also NERC, Events Analysis
Modeling Notification Recommended Practices for
Modeling Momentary Cessation Initial Distribution,
1 n.4 (Feb. 2018), https://www.nerc.com/comm/PC/
NERCModelingNotifications/Modeling_
Notification_-_Modeling_Momentary_Cessation_-_
2018-02-27.pdf (explaining that more detailed
vendor-specific models may be used for local
planning studies; however, they are generally not
allowed or recommended for building
interconnection-wide models).
98 See, e.g., EPRI, Model User Guide for Generic
Renewable Energy System, 2 (June 2015), https://
www.epri.com/research/products/
000000003002006525 (explaining that the ‘‘models
presented here were developed primarily for the
purpose of general public use and benefit and to
eliminate the long standing issues around many
vendor-specific models being proprietary and thus
neither publicly available nor easily disseminated
among the many stakeholders. Furthermore, using
multiple user-defined non-standard models within
large interconnection studies, in many cases,
presented huge challenges and problems with
effectively and efficiently running the
simulations.’’).
99 NERC Standardized Powerflow Parameters and
Dynamics Models at 1 (explaining that there is a
growing need for accurate interconnection-wide
power flow and dynamics simulations that analyze
phenomena such as: frequency response, inter-area
oscillations, and interactions between the growing
numbers of wide-area control and protections
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field-testing data.100 The currently
effective Reliability Standards MOD–
026–1 (Verification of Models and Data
for Generator Excitation Control System
or Plant Volt/Var Control Functions) 101
and MOD–027–1 (Verification of Models
and Data for Turbine/Governor and
Load Control or Active Power/
Frequency Control Functions) 102
require each generator owner to verify
models and data for specific
components of synchronous resources
(e.g., generator excitation control
systems, plant volt/var control
functions, turbine/governor and load
controls, and active power/frequency
controls), but they do not require a
generator owner to provide verified
models and data for IBR-specific
controls (e.g., power plant central
controller functions and protection
system settings) to its transmission
planner. Additionally, the currently
effective Reliability Standards neither
require the transmission owner for
unregistered IBRs to provide verified
dynamic models nor require
distribution providers to provide
verified dynamic models of IBR–DERs
in the aggregate to their transmission
planners. Finally, the currently effective
Reliability Standards neither require the
transmission owner for unregistered
IBRs nor the distribution providers for
IBR–DERs in the aggregate to submit the
respective dynamic models to the
applicable registered entities that
perform planning and operations
functions.
46. Once the generator owners for
registered IBRs, transmission owners for
unregistered IBRs, and distribution
providers for IBR–DERs in the aggregate
verify plant models, Bulk-Power System
planners and operators must validate
and update system models (i.e.,
planning and operation transmission
area models as well as interconnectionwide models) by comparing the
provided data and resulting system
models against actual system
operational behavior. While Reliability
Standard MOD–033–2 (Steady State and
Dynamic System Model Validation)
requires validation using real-world
data of the interconnection-wide
100 Id. (explaining that the NERC Modeling
Working Group was tasked to develop, validate, and
maintain a library of standardized component
models and parameters for powerflow and
dynamics cases. The standardized models in these
libraries have documentation describing their
model structure, parameters, and operation. This
information has been vetted by the industry and
thus deemed appropriate for widespread use in
interconnection-wide analysis).
101 See Reliability Standard MOD–026–1.
102 See Reliability Standard MOD–027–1.

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model,103 the currently effective
Reliability Standards lack clarity as to
whether models of registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate are required to represent the
real-world behavior of the equipment
installed in the field during
interconnection-wide disturbances that
have exhibited common mode failures
of IBRs.104
47. Once Bulk-Power System planners
and operators validate system
models,105 there must be additional
requirements for generator owners,
transmission owners, and distribution
providers to communicate with BulkPower System planners and operators to
ensure that any changes to IBR settings,
configurations, and ratings are updated.
Otherwise, the transmission system
models will not adequately represent
the behavior of the actual installed
equipment.106 While Reliability
Standards MOD–032–1 and MOD–033–
2 include iterative updating and
validation processes, Reliability
Standard MOD–032–1 does not require
IBR-specific modeling data and
parameters, and Reliability Standard
MOD–033–2 does not contemplate the
technology-specific performance
characteristics of registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate.
48. Once Bulk-Power System planners
and operators have validated system
models, Bulk-Power System planners
and operators need to coordinate with
generator owners, transmission owners,
and distribution providers so that the
system models adequately represent all
generation resources—including
registered IBRs, unregistered IBRs, IBR–
DERs in the aggregate, and synchronous
generation—as well as load. Reliability
Standards MOD–032–1 and MOD–033–
2 do not require the applicable entities
to work collaboratively to create
interconnection-wide models that
103 Reliability Standard MOD–033–2,
Requirements R1, R2.
104 NERC annually assesses the interconnectionwide model quality and publishes a report to help
entities responsible for complying with Reliability
Standard MOD–032 to resolve model issues and
improve the cases. NERC’s 2021 Case Quality
Metrics Assessment indicates that planners are not
able to develop accurate system models (e.g., all
interconnections demonstrate either a consistent
performance or worsening score in the unacceptable
or not recommended model metrics). See NERC,
Case Quality Metrics Annual Interconnection-wide
Model Assessment, 26–29 (Oct. 2021), https://
www.nerc.com/pa/RAPA/ModelAssessment/
ModAssessments/2021_Case_Quality_Metrics_
Assessment-FINAL.pdf.
105 This final action uses ‘‘validation’’ to mean the
confirmation that a model reflects real world
operational behaviors and uses ‘‘verification’’ to
mean a model is properly parameterized and
validated.
106 See NOPR, 181 FERC ¶ 61,125 at P 39 n.91.

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accurately reflect the real-world
interconnection-wide performance and
behavior of registered and unregistered
IBRs individually and in the aggregate,
as well as IBR–DERs in the aggregate.107
As a result, the models developed and
deployed in compliance with these
standards do not contemplate that IBRs
can reduce power, trip offline, or enter
momentary cessation individually or in
the aggregate in response to a single
fault on a transmission or subtransmission system.

NERC has stated that the currently
effective Reliability Standards do not
mitigate the IBR reliability risks because
the IBR issues are not properly detected
by models and studies.109 NERC has
also found that there is an immediate
need to enhance the currently effective
Reliability Standards. NERC explains
that there is a need to understand the
extent of inverter performance risks and
modeling deficiencies as well as to
gather necessary data for the currently
installed fleet.110

3. Planning and Operational Studies
49. Once Bulk-Power System planners
and operators have validated registered
IBR, unregistered IBR, and IBR–DER
aggregate modeling and operational
data, the Reliability Standards must
require that Bulk-Power System
planning and operational studies
account for the actual behavior of both
registered IBRs and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate. The
Reliability Standards do not require
Bulk-Power System planning and
operational studies to assess the
performance and behavior of both
registered and unregistered IBRs
individually and in the aggregate (e.g.,
IBRs tripping or entering momentary
cessation individually or in the
aggregate), as well as IBR–DERs in the
aggregate. Reliability Standard TPL–
001–5.1 (Transmission System Planning
Performance Requirements) requires
planning coordinators and transmission
planners to plan to ensure reliable
operations over a broad spectrum of
system conditions and following a wide
range of probable contingencies, but it
does not require planning coordinators
and transmission planners to assess the
performance and behavior of registered
and unregistered IBRs individually and
in the aggregate, or IBR–DERs in the
aggregate, during normal and
contingency conditions for the reliable
operation of the Bulk-Power System.108

4. Performance Requirements

107 Reliability Standard MOD–032–1 is applicable
to the following registered entities: (1) balancing
authorities, (2) generator owners, (3) planning
authorities/planning coordinators, (4) load serving
entity, (5) resource planners, (6) transmission
owners, (7) transmission planners, and (8)
transmission service providers. NERC has
deregistered the load serving entity function and
has an ongoing standard drafting team project to
replace this function as an applicable entity in the
Reliability Standards with the distribution provider
function. See Project–2022–02 Modifications to
TPL–001 and MOD–032.
108 Reliability Standard TPL–001–5.1
(Transmission System Planning Performance
Requirements) was approved by the Commission
and became effective on July 1, 2023. See N. Am.
Elec. Reliability Corp., Docket No. RD20–8–000
(June 10, 2020) (delegated letter order) (approving
a NERC-proposed erratum to Reliability Standard
TPL–001–5); Transmission Plan. Reliability

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50. The currently effective Reliability
Standards do not account for the
differences in response of registered
IBRs and synchronous generation
resources during normal and
contingency conditions. The frequency
of an interconnection depends on the
instantaneous balance between load and
generation resources, to which all
resources contribute during both normal
and contingency conditions. For
frequency to be maintained, generation
resources must remain connected to the
grid and continue to support grid
frequency (i.e., ride through) during
either loss of generation
(underfrequency) or loss of load
(overfrequency) related frequency
deviations. Reliability Standard PRC–
024–3 does not require registered IBRs
(or any generator) to remain connected
to the Bulk-Power System and to
continue to inject current and support
frequency inside the ‘‘no trip zone.’’ 111
Therefore, IBRs could continue to act
adversely in response to normally
cleared faults by continuing to exhibit
momentary cessation and power
reduction behaviors.
51. In addition, the currently effective
Reliability Standards do not require
registered IBRs to continually inject
current and support voltage inside the
‘‘no trip zone’’ during a voltage
Standard TPL–001–5, Order No. 867, 170 FERC
¶ 61,030 (2020) (approving Reliability Standard
TPL–001–5).
109 See Odessa 2021 Disturbance Report at 43
(explaining that ‘‘[p]lants are abnormally
responding to [Bulk-Power System] disturbance
events and ultimately tripping themselves off-line.
These issues are not being properly detected by the
models and studies conducted during the generator
interconnection study process nor during annual
planning assessments.’’).
110 Odessa 2022 Disturbance Report at vii–ix.
111 Reliability Standard PRC–024–3 is a voltage
and frequency protection settings standard that
specifies that a generating resource may neither trip
nor enter momentary cessation (i.e., cease injecting
current) inside the boundaries of the frequency and
voltage excursion curves. The area inside the
boundaries of the frequency and voltage excursion
curves is known as the ‘‘no-trip zone.’’ See also
Reliability Standard PRC–024–3, attach. 1, nn.8, 9.

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excursion.112 The Reliability Standards
also do not contain voltage ride through
performance requirements that address
the unique protection and control
functions of registered IBRs that can
cause tripping and momentary
cessation, even when the IBR voltage
protection settings comply with
Reliability Standard PRC–024–3.
52. Finally, the currently effective
Reliability Standards do not require all
generation resources that momentarily
cease operation following a system
disturbance to return to pre-disturbance
output levels without impeded ramp
rates or require that all generation
resources maintain voltage phase angle
synchronization with the Bulk-Power
System grid voltage during a system
disturbance. IBRs that lose
synchronization with grid voltage (i.e.,
phase lock loop loss of synchronism)
will momentarily cease current injection
into the grid during Bulk-Power System
disturbance events due to protection
and control settings. Such momentary
cessation occurrences exacerbate system
disturbances and have a material impact
on the reliable operation of the BulkPower System.113
IV. Discussion
53. As discussed below, the
Commission finds that the currently
effective Reliability Standards do not
adequately address the risks posed by
the increasing numbers of IBRs
connecting to the Bulk-Power System.
As noted by NERC in its initial
comments, IBRs can introduce
significant risks to the Bulk-Power
System if not integrated properly, and
NERC sees addressing such risks as a
high priority for the ERO.114 While
NERC has initiated various projects to
address aspects of IBR reliability, we
find that the actions we take in this final
action are necessary to maintain the
reliable operation of the Bulk-Power
System. Accordingly, pursuant to
section 215(d)(5) of the FPA, we adopt
the NOPR proposals with some
modifications and direct NERC to
develop and submit new or modified
Reliability Standards that address the
impacts of IBRs on the reliable
operation of the Bulk-Power System.
Given the current and projected increase
in the proportion of IBRs within the
112 The NOPR used both terms current and power
when proposing to direct NERC to develop new or
modified Reliability Standards that address
registered IBRs’ performance requirements. For
clarity in this final action, we only use ‘‘current’’
when directing NERC to develop new or modified
Reliability Standards that address registered IBRs’
performance requirements.
113 See NOPR, 181 FERC ¶ 61,125 at P 4.
114 NERC Initial Comments at 2.

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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations
Bulk-Power System generation fleet, and
for the reasons discussed in section III
above, we conclude that it is necessary
to direct NERC to develop new or
modified Reliability Standards that
address the following specific matters:
(1) generator owner data sharing for
registered IBRs, transmission owner
data sharing for unregistered IBRs, and
distribution provider data sharing for
IBR–DERs in the aggregate; (2) data and
model validation for registered and
unregistered IBRs and IBR–DERs in the
aggregate; (3) planning and operational
studies for registered and unregistered
IBRs individually and in the aggregate
and for IBR–DERs in the aggregate; and
(4) registered IBR performance
requirements.
54. In directing the ERO to submit
new or modified Reliability Standards,
we do not direct a specific method for
addressing the reliability concerns
discussed herein. Rather, in this final
action we identify issues that should be
addressed in the NERC standards
development process. Further, NERC
has the discretion, subject to
Commission review and approval, as to
how to address the reliability concerns
described below by developing one or
more new Reliability Standards or
modifying currently effective Reliability
Standards. We direct NERC to develop
new or modify the currently effective
Reliability Standards to address these
issues and, when these Reliability
Standards are submitted to the
Commission for approval, to explain in
the accompanying petition how the
issues are addressed in the proposed
new or modified Reliability Standards.
NERC may propose to develop new or
modified Reliability Standards that
address our concerns in an equally
efficient and effective manner; however,
NERC’s proposal should explain how
the new or modified Reliability
Standards address the Commission’s
concerns discussed in this final
action.115
55. We modify the NOPR proposal
and direct NERC to submit an
informational filing within 90 days of
the issuance of the final action in this
proceeding that includes a detailed,
comprehensive standards development
plan explaining how NERC will
prioritize the development of new or
modified Reliability Standards to meet
the deadlines set out below, taking into
account the risk posed to the reliability
of the Bulk-Power System, standard
development projects already
underway, resource constraints, and
other factors if necessary.
115 See, e.g., Order No. 693, 118 FERC ¶ 61,218 at
PP 186, 297.

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56. As discussed below, we are
persuaded by commenters’ suggestions
regarding the proposed staggered
groupings for new or modified
Reliability Standards, and we modify
the NOPR proposal to adopt NERC’s
proposed staggered grouping that would
result in NERC submitting new or
modified Reliability Standards in three
stages.116 Therefore, in its
comprehensive standards development
plan, NERC must submit new or
modified Reliability Standards by the
following deadlines. First, by November
4, 2024, NERC must submit new or
modified Reliability Standards that
establish IBR performance requirements,
including frequency and voltage ride
through, post-disturbance ramp rates,
phase lock loop synchronization, and
other known causes of IBR tripping or
momentary cessation. NERC must also
submit, by November 4, 2024, new or
modified Reliability Standards that
require disturbance monitoring data
sharing and post-event performance
validation for registered IBRs. Second,
by November 4, 2025, NERC must
submit new or modified Reliability
Standards addressing the interrelated
directives concerning: (1) data sharing
for registered IBRs, unregistered IBRs,
and IBR–DERs in the aggregate; and (2)
data and model validation for registered
IBRs, unregistered IBRs, and IBR–DERs
in the aggregate. Finally, by November
4, 2026, NERC must submit new or
modified Reliability Standards
addressing planning and operational
studies for registered IBRs, unregistered
IBRs, and IBR–DER in the aggregate.
NERC may expedite its development
plan and submit new or modified
Reliability Standards prior to the
deadlines.
57. While the NOPR proposed
directing NERC to include
implementation dates (i.e., when the
standards would become mandatory and
enforceable) in its standards
development plan, we are persuaded by
NERC’s comments that the
implementation of new or modified
Reliability Standards is better
determined through the NERC standards
drafting process. Therefore, we do not
adopt the NOPR proposal to direct
NERC to include implementation dates
in its standards development plan.
Rather, the Commission will consider
the justness and reasonableness of each
new or modified Reliability Standard’s
implementation plan when it is
116 In the NOPR, the Commission proposed a
staggered approach that would result in NERC
submitting new or modified Reliability Standards in
three stages. See NOPR, 181 FERC ¶ 61,125 at PP
8, 73. In the final action, we are changing the
content of the three staggered filings.

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submitted for Commission approval.117
However, as discussed above, the
number of events, NERC Alerts, reports,
whitepapers, guidelines, and ongoing
standards projects demonstrate the need
for the expeditious implementation of
new or modified Reliability Standards
addressing IBR data sharing, data and
model validation, planning and
operational studies, and performance
requirements.118 Accordingly, the
Commission will take these issues into
account when it considers the proposed
implementation plan for each new or
modified Reliability Standard when it is
submitted to the Commission for
review. Moreover, as a general matter,
we believe that there is a need to have
all of the directed Reliability Standards
effective and enforceable well in
advance of 2030, at which time IBRs are
projected to account for a significant
share of the electric energy generated in
the United States.119
58. We address below in further detail
issues raised in the NOPR and in
comments regarding: (A) Commission
authority to direct the ERO to develop
new or modified Reliability Standards
under FPA section 215(d)(5); (B) data
sharing, including registered IBR data,
disturbance monitoring data,
unregistered IBR data, and data for IBR–
DERs in the aggregate; (C) data and
model validation, including approved
models, dynamic model performance,
validation of system models, and
coordination; (D) planning and
operational studies; (E) performance
requirements; and (F) the informational
filing and associated timeline for
Reliability Standard development.
A. Commission Authority To Direct the
ERO To Develop New or Modified
Reliability Standards Under Section 215
of the FPA
59. In the NOPR, the Commission
preliminarily found that the currently
117 See Order No. 672, 114 FERC ¶ 61,104 at P 333
(‘‘In considering whether a proposed Reliability
Standard is just and reasonable, the Commission
will consider also the timetable for implementation
of the new requirements, including how the
proposal balances any urgency in the need to
implement it against the reasonableness of the time
allowed for those who must comply.’’).
118 See supra P 7.
119 See, e.g., U.S. Energy Information Admin.,
Annual Energy Outlook 2023 (Mar. 16, 2023),
https://www.eia.gov/outlooks/aeo/narrative/
index.php#TheElectricityMixinth (projecting that
renewables will account for a significant portion of
the electric energy generated in the United States
by 2030). The U.S. Energy Industry Association
defines the major types of renewable energy sources
to include resources such as biomass, hydropower,
geothermal, wind, and solar (e.g., Stirling cycle,
solar PV, and concentric solar). See https://
www.eia.gov/energyexplained/renewable-sources/.
Of these resources, solar PV and wind generation
are IBRs.

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effective Reliability Standards do not
adequately address the impacts of IBRs
on the reliable operation of the BulkPower System.120 The NOPR stated that
this constitutes a reliability gap in the
areas of: (1) data sharing; (2) model
validation; (3) planning and operational
studies; and (4) performance
requirements. To carry out section 215
of the FPA, the NOPR proposed to direct
NERC to develop and submit for
approval new or modified Reliability
Standards that address IBRs and their
impacts on the reliable operation of the
Bulk-Power System.
1. Comments
60. NERC supports the Commission’s
efforts and agrees that the currently
effective Reliability Standards must be
enhanced to address the reliability risks
posed by IBRs.121 Further, NERC and
the majority of commenters that
responded on this topic generally
support the four topic areas for new or
modified Reliability Standards (i.e., data
sharing, model validation, planning and
operational studies, and performance
requirements) that the Commission
outlined in the NOPR.122
61. Commenters agree that IBRs affect
the reliable operation of the Bulk-Power
System and that some modifications to
the currently effective Reliability
Standards are warranted.123 For
example, IRC states that IBRs may have
an impact on the reliability of the BulkPower System regardless of their size,
registration status, or their
interconnection level (i.e., connected to
transmission or distribution).124 ACP/
SEIA agree there is a need for clarity
and consistency for IBRs and their
Reliability Standard obligations.125 EPRI
states that its research and collaboration
has shown that uniform technical
performance requirements, including
ride through requirements, can support
system reliability.126 Indicated Trade
Associations agree that it is necessary to
manage the impact of the increase of
IBRs on the Bulk-Power System through
new or modified Reliability
Standards.127
120 NOPR,

181 FERC ¶ 61,125 at P 68.
Initial Comments at 7.
122 See, e.g., id.; AEP Initial Comments at 2;
Bonneville Initial Comments at 1; CAISO Initial
Comments at 1; NYSRC Initial Comments at 1.
123 See, e.g., AEU Initial Comments at 2 (agreeing
the IBRs may cause adverse reliability impacts and
contribute reliability benefits to the Bulk-Power
System); InfiniRel Initial Comments at 1 (stating
that ‘‘[n]ew or modified Reliability Standards are
necessary to address the IBR-related reliability
gaps’’).
124 IRC Initial Comments at 2.
125 ACP/SEIA Initial Comments at 4.
126 EPRI Initial Comments at 4.
127 Indicated Trade Association Comments at 1.

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62. Ohio FEA, noting that the majority
of IBR-related events discussed in the
NOPR predominantly took place in
Texas and California, defers to the
Commission’s findings regarding gaps in
the currently effective Reliability
Standards for IBRs and emphasizes that
it is the Commission’s role within its
FPA section 215 authority to protect
Bulk-Power System reliability by
directing NERC to develop new or
modified Reliability Standards.128
Nevertheless, Ohio FEA also notes that
the definition of ‘‘Bulk-Power System’’
does not include facilities used in the
local distribution of electric energy; and
Ohio FEA emphasizes that there is a
dividing line between the Commission’s
authority over the Bulk-Power System
and its authority over its distribution
system.129 Further, Ohio FEA cautions
that there could be potential conflicts in
the reliability objectives, standards, and
guidelines related to IBRs on the
transmission system versus the
distribution system.130
2. Commission Determination
63. We find that the directives in this
final action are a valid exercise of the
Commission’s authority pursuant to
FPA section 215(d)(5). The plain
language of the statute authorizes the
Commission to order the development
of a Reliability Standard that ‘‘addresses
a specific matter if the Commission
considers such a new or modified
Reliability Standard appropriate to carry
out this section.’’ 131
64. We determine that directing
NERC, as the ERO, to address the
specific matters pertaining to IBRs and
their impact on the reliable operation of
the Bulk-Power System is appropriate to
carry out FPA section 215. As the NOPR
stated, and as discussed in section III
above, there are multiple ERO findings
of the reliability impacts of IBRs,
including guidelines, white papers,
assessments, event reports, and NERC
Alerts, among others. Further, NERC has
already begun efforts to address IBR
reliability issues through projects to
improve the mandatory Reliability
Standards.132 As Bulk-Power System
events continue to occur and the risks
that IBRs can pose to reliable operation
of the Bulk-Power System are
demonstrated, there is an urgent need to
128 Ohio

FEA Initial Comments at 4.
at 5.
130 Ohio FEA notes that transmission system
operators prefer generators to ride-through short
duration transmission faults, while distribution
system operators typically prefer generators to trip
off during distribution faults. Ohio FEA Initial
Comments at 6.
131 16 U.S.C. 824o(d)(5).
132 See supra P 32.
129 Id.

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develop and implement mandatory
Reliability Standards to address these
issues on a nationwide basis.
65. Section 215 of the FPA defines
‘‘reliability standard’’ as a requirement
to provide for reliable operation of the
Bulk-Power System.133 FPA section 215
defines ‘‘reliable operation’’ to mean
operating Bulk-Power System elements
within their thermal, voltage, and
stability limits to prevent or avoid
instability, uncontrolled separation, or
cascading failures as a result of a
sudden disturbance, including a
cybersecurity incident, or unanticipated
failure of system elements.134 We are
aware of the Commission’s
jurisdictional boundaries as noted by
Ohio FEA. Thus, the directives in this
final action are to NERC as the ERO to
develop new or modified Reliability
Standards to require the reliable
operation of the Bulk-Power System.
While certain directives pertain to
registered entities such as distribution
providers obtaining aggregate data for
IBR–DERs, the final action does not
impose any requirements on nonregistered entities or facilities used in
the local distribution of electric
energy.135 Regarding Ohio FEA’s
concerns about the need for
coordination between transmission
system operators and distribution
providers regarding their different
performance requirements,136 as the
Commission has explained, the IBR
Registration Order and NERC’s related
work plan do not address the
registration of IBR–DERs.137 NERC has
committed to examine potential impacts
of IBR–DERs on the reliable operation of
the Bulk-Power System; thus, we would
expect that as a part of NERC’s
communication plan it would consider
how to address related coordination
issues between transmission operators
and distribution providers.138
133 16

U.S.C. 824o(a)(3).
824o(a)(4).
135 Id. 824o(a)(1).
136 Ohio FEA notes that transmission system
operators prefer generators to ride-through short
duration transmission faults, while distribution
system operators typically prefer generators to trip
off during distribution faults. Ohio FEA Initial
Comments at 6.
137 See Order Approving Workplan, 183 FERC
¶ 61,116 at P 48 (citing IBR Registration Order, 181
FERC ¶ 61,124 at P 1 n.1 (stating that the order does
not address IBRs connected to the distribution
system)). See also id. P 1 n.2 (citing 16 U.S.C.
824o(a)(1), which explains that the term ‘‘BulkPower System’’ does not include facilities used in
the local distribution of electric energy).
138 See Id. P 15 (explaining that NERC’s
communication plan outlines how NERC will
coordinate with key stakeholders).
134 Id.

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B. Data Sharing
66. In the NOPR, the Commission
preliminarily found that the existing
Reliability Standards are inadequate to
ensure that sufficient data of registered
IBRs and unregistered IBRs, and data of
IBR–DERs in the aggregate, are provided
to the registered entities responsible for
planning, operating, and analyzing
disturbances on the Bulk-Power
System.139 The Commission observed
that the currently effective Reliability
Standards, such as TOP–003–5
(Operational Reliability Data) and IRO–
010–4 (Reliability Coordinator Data
Specification and Collection),140 require
the data recipient to specify a list of data
to be provided, and obligates other
identified registered entities to provide
the specified data. The Commission
preliminarily found that these and other
currently effective data-related
Reliability Standards do not require
generator owners, generator operators,
transmission owners, and distribution
providers to provide data that represents
the behavior of both registered and
unregistered IBRs individually and in
the aggregate, as well as data of IBR–
DERs in the aggregate, at a sufficient
level of fidelity for Bulk-Power System
planners and operators to accurately
plan for, operate during, and analyze
disturbances on the Bulk-Power
System.141
67. To address this data sharing gap
in the currently effective Reliability
Standards, the Commission proposed to
direct NERC to develop new or modified
Reliability Standards that identify: (1)
the registered entities that must provide
certain data of registered IBRs and
unregistered IBRs, as well as IBR–DER
data in the aggregate; (2) the recipients
of that registered IBR, unregistered IBR,
and IBR–DER in the aggregate data; (3)
the minimum categories or types of
registered IBR, unregistered IBR, and
IBR–DER in the aggregate related data
that must be provided; and (4) the
timing and periodicity for the provision
of registered IBR, unregistered IBR, and
IBR–DER in the aggregate data needed
for modeling, operations, and
disturbance analysis to the appropriate
registered entities and the review of that
data by those entities.142
1. Registered IBR Data Sharing
68. In the NOPR, the Commission
proposed to direct NERC to develop
new or modified Reliability Standards
139 NOPR,

181 FERC ¶ 61,125 at P 76.
Standard TOP–003–5 and
Reliability Standard IRO–010–4 became effective
April 1, 2023.
141 NOPR, 181 FERC ¶ 61,125 at P 76.
142 Id. P 77.
140 Reliability

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that require generator owners and
generator operators of registered IBRs to
provide registered IBR-specific
modeling data and parameters (e.g.,
steady-state, dynamic, and short circuit
modeling information, and control
settings for momentary cessation and
ramp rates) that accurately represents
IBRs to their planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities that are
responsible for planning and operating
the Bulk-Power System.143 The
Commission explained that this
approach would provide the registered
entities responsible for planning and
operating the Bulk-Power System with
accurate data on registered IBRs.144
a. Comments
69. Commenters generally support the
proposed directive to require IBR
generator owners and generator
operators to provide registered IBRspecific modeling data and parameters
to planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities.145
70. NERC states that poor or
inadequate IBR data, models, and
information have proven to be a
significant issue. For example, generator
owners may provide modeling data and
information that is generic or based on
default parameters that do not reflect
the as-built facility.146 NERC states that
providing adequate modeling data and
information is critical to create and
maintain models that represent
necessary modeling data quality and
accuracy, adding that data accuracy,
completeness, usability, and fidelity
should be explicitly defined, tested, and
verified by all applicable entities,
particularly for modeling information
used in reliability studies.147
71. Indicated Trade Associations and
APS explain that the currently effective
Reliability Standards may not ensure
that transmission planners or operators
have all necessary criteria and metrics
to plan for and reliably integrate certain
IBRs on the Bulk-Power System.148
CAISO explains that its experience
shows that modern IBRs are capable of
complying with data sharing and data
143 Id.

P 78.

144 Id.
145 See, e.g., NERC Initial Comments at 8; CAISO
Initial Comments at 24.
146 NERC Initial Comments at 8.
147 Id. at 8–9.
148 Indicated Trade Associations Initial
Comments at 4–5; APS Initial Comments at 2
(indicating it largely supports Indicated Trade
Associations Initial Comments but providing
additional comments on specific topics).

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and model validation requirements.149
Further, CAISO supports national
standards establishing data sharing, and
data and model validation guidelines, as
a patchwork approach would be
inefficient (e.g., a significant number of
IBRs participating in the CAISO’s
markets are not bound by the currently
effective Reliability Standards and
CAISO’s standards do not bind across
the Western Electricity Coordinating
Council).150
72. SPP states that it has heard from
IBR owners that they have concerns that
some IBR data (and IBR–DER data) may
be considered proprietary by
manufacturers and difficult to obtain.
Nevertheless, SPP contends that such
concerns should not obstruct reliability
improvements and suggests that the
final action should provide the correct
incentive for IBR owners to either use
equipment that meets data sharing
requirements (i.e., equipment that is not
proprietary) or develop agreements or
other protections for IBR data that is
considered proprietary.151
73. ACP/SEIA suggest modifying the
directives to require generator owners
and operators to share IBR data. ACP/
SEIA recommend that, rather than
mandating specific modeling and data
submissions, planning entities should
have flexibility to identify the data they
need for their operations and planning
activities, and that the new or modified
Reliability Standards should ensure that
the data requested is reasonable and
necessary for improving reliability.152
74. AEU and ACP/SEIA ask that, in
addition to data provision requirements
for generator owners and operators, the
Commission direct NERC to specify data
sharing requirements from transmission
owners to generator owners.153 For
example, AEU explains that generator
owners and operators also require data
from transmission owners to support
accurate modeling and performance,
e.g., short circuit data, grid data for
offshore wind, information on other
power electronic devices around the IBR
plant, and voltage harmonics.154 AEU
adds that putting requirements on
transmission owners would be
consistent with revisions being
developed for NERC’s Modeling, Data,
and Analysis (MOD) Reliability
Standards.155
75. ACP/SEIA, Mr. Plankey, and Ohio
FEA raise security concerns and the
149 CAISO

Initial Comments at 7.
at 30–31.
151 SPP Initial Comments at 2.
152 ACP/SEIA Initial Comments at 11–12.
153 AEU Initial Comments at 4; ACP/SEIA Initial
Comments at 12–13.
154 AEU Initial Comments at 4.
155 Id. at 5.
150 Id.

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need for accountability and protection
of data sharing.156 Ohio FEA
recommends that NERC’s Electricity
Information Sharing and Analysis
Center (E–ISAC) could serve as a
facilitator for IBR data sharing.157
b. Commission Determination

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76. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop new or
modified Reliability Standards that
require registered IBR generator owners
and operators to provide IBR-specific
modeling data and parameters (e.g.,
steady-state, dynamic, and short circuit
modeling information, and control
settings for momentary cessation and
ramp rates) that accurately represent the
registered IBRs to their planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities that
are responsible for planning and
operating the Bulk-Power System. As
several commenters indicate, ensuring
the sharing of appropriate IBR modeling
data is critical to create and maintain
the models used in reliability studies,
and in turn to ensure that Bulk-Power
System transmission planners or
operators are able to plan for, operate,
and reliably integrate IBRs onto the
Bulk-Power System.
77. With regard to AEU and ACP/
SEIA’s comments that the Commission
direct NERC to specify data sharing
requirements from transmission owners
to generator owners and operators, we
believe that this request may already be
addressed through each transmission
planner’s existing processes. For
example, the New York Independent
System Operator (NYISO) and CAISO
both have processes for obtaining such
data after demonstrating a need for the
specific information requested and that
the required information protection and
non-disclosure agreements are
signed.158 Nevertheless, to support
accurate modeling and performance, we
direct NERC to consider during its
standards development process AEU
and ACP/SEIA’s suggested data sharing
requirements when developing the
156 ACP/SEIA Initial Comments at 12; Mr.
Plankey Initial Comments at 1; Ohio FEA Initial
Comments at 9.
157 Ohio FEA Initial Comments at 9.
158 See NYISO, What to expect when submitting
a CEII Request form (Sep. 9, 2021), https://
nyiso.force.com/MemberCommunity/s/article/
What-to-expect-when-submitting-a-CEII-Requestform; CAISO, Application access, http://
www.caiso.com/participate/Pages/
ApplicationAccess/Default.aspx (explaining that
the process for secure planning and market systems
data are available upon compliance with the
applicable submission instructions and submittal of
a non-disclosure agreement).

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framework, criteria, and necessary data
exchange requirements to meet the
registered IBR data sharing directive.
78. Commenters raised general
concerns that mandating specific
modeling and data submissions would
reduce the flexibility and discretion of
transmission planners and operators to
identify the information they need. We
find that, given the need for IBRs to
operate in a predictable and reliable
manner to ensure the reliable operation
of the Bulk-Power System, it is
necessary to establish uniform,
minimum categories or types of data
that must be provided so that BulkPower System planners and operators
can predict the behavior of all IBRs. As
discussed in more detail in section IV.C
of this final action, we are also directing
NERC to develop new or modified
Reliability Standards that require the
use of approved industry IBR models
that accurately reflect the behavior of all
IBRs during steady state, short-circuit,
and dynamic conditions.
79. With regard to SPP’s comment
that some IBR data (and IBR–DER data)
may be considered proprietary (userdefined) by manufacturers and difficult
to obtain, we believe that the directives
in this final action should facilitate the
provision of IBR data and address these
concerns further in the determination
section IV.C.1 of this final action.
80. The Commission did not propose
in the NOPR to address new cyber or
physical security protections of IBRs
beyond those in existing applicable
Reliability Standards. Therefore, while
we decline to direct NERC to develop
IBR-specific cyber or physical security
Reliability Standards for IBRs in this
effort, NERC should evaluate whether
there are gaps that must be addressed.
We decline to direct that the NERC E–
ISAC facilitate all IBR data sharing, as
these suggestions fall outside the scope
of this proceeding.
2. Disturbance Monitoring Data Sharing
81. In the NOPR, the Commission
proposed to direct NERC to develop
new or modified Reliability Standards
that include technical criteria for
disturbance monitoring equipment
installed at buses and elements of
registered IBRs to ensure disturbance
monitoring data is available to BulkPower System planners and operators
for analyzing disturbances on the BulkPower System and to validate registered
IBR models.159
a. Comments
82. NERC, ACP/SEIA, CAISO,
Indicated Trade Associations, and
159 NOPR,

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NYSRC support the proposed directive
regarding disturbance monitoring
data.160 NERC agrees that disturbance
monitoring data is fundamental for
model validation and post-event
analysis activities, and to identify
reliability risks. NERC and Indicated
Trade Associations both point to NERC
Project 2021–04 (Modifications to
Reliability Standard PRC–002–2), a
NERC standard development project to
modify disturbance monitoring and
reporting requirements so that BulkPower System-connected IBRs are
monitored in order to better assess
disturbances.161 NERC explains that the
currently effective Reliability Standard
PRC–002–2 was originally written with
synchronous generation in mind, as that
was the predominant form of generation
in use at the time.162 Thus, NERC
explains that it is necessary to update
currently effective Reliability Standard
PRC–002–2 so that it requires registered
IBRs to provide minimum disturbance
monitoring data 163 to the planning
coordinator or reliability coordinator,
Regional Entity, or NERC.
83. CAISO encourages the
Commission to direct NERC to consider
requiring IBRs to provide additional
data, whether through telemetry
collections or other automated platform
integrations, to enhance real-time
visibility of Bulk-Power System
operations.164
84. ACP/SEIA agree with the
proposed disturbance monitoring
directive but caution that there is a need
to balance the burden to the generator
of collecting and providing the data
with the benefit of that data to
reliability, e.g., requiring high-speed
data collection from every inverter at a
plant is unnecessary because each
inverter would provide nearly identical
data.165
b. Commission Determination
85. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
to direct NERC to include in the new or
modified Reliability Standards technical
criteria to require registered IBR
generator owners to install disturbance
monitoring equipment at their buses
160 See NERC Initial Comments at 9; ACP/SEIA
Initial Comments at 12; CAISO Initial Comments at
39–40; Indicated Trade Associations Initial
Comments at 6; NYSRC Initial Comments at 2.
161 NERC Initial Comments at 9; Indicated Trade
Associations Initial Comments at 6.
162 See NERC Initial Comments at 9.
163 Disturbance monitoring data collection may
include sequence of events recording, digital fault
recording, synchronized phasor measurement unit
recording, inverter oscillography recording data,
and inverter and plant-level fault codes.
164 CAISO Initial Comments at 40.
165 ACP/SEIA Comments at 12.

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and elements, to require registered IBR
generator owners to provide disturbance
monitoring data to Bulk-Power System
planners and operators for analyzing
disturbances on the Bulk-Power System,
and to require Bulk-Power System
planners and operators to validate
registered IBR models using disturbance
monitoring data from installed
registered IBR generator owners’
disturbance monitoring equipment.166
We agree with NERC that updating
Reliability Standard PRC–002–2 to
apply to registered IBRs for disturbance
monitoring data collection, including
recording sequence of events, digital
faults, synchronized phasor
measurements, inverter oscillography,
inverter and plant-level fault codes, and
data retention, could be one way to
accomplish this directive. We further
agree with the findings in NERC reports
(e.g., a lack of high-speed data captured
at the IBR or plant-level controller and
low-resolution time stamping of inverter
sequence of event recorder information
has hindered event analysis) and direct
NERC through its standard development
process to address these findings.167
86. As a general matter, we agree with
ACP/SEIA regarding the need to balance
the burden to generator owners of
collecting and providing data collected
by disturbance monitoring equipment
with the benefit of that data to
reliability. Thus, in developing the
directed data collection requirements,
we direct NERC to consider the burdens
of generators collecting and providing
data, while assuring that Bulk-Power
System operators and planners have the
data they need for accurate disturbance
monitoring and analysis.168 Likewise,
regarding CAISO’s request that the
Commission direct NERC to consider
requiring registered IBRs to provide
additional data, we agree that such data
collections may be warranted, and
direct NERC to consider through its
standards development process whether
166 See NERC, NERC Inverter-Based Resource
Performance Task Force (IRPTF)Review of NERC
Reliability Standards White Paper, at 1 (Mar. 2020),
https://www.nerc.com/pa/Stand/Project202104
ModificationstoPRC0022DL/Review_of_NERC_
Reliability_Standards_White_Paper_062021.pdf
(explaining that PRC–002–2 should be revised to
require disturbance monitoring equipment in areas
not currently contemplated by the existing
requirements, specifically in areas with potential
inverter-based resource behavior monitoring
benefits); see also Odessa Disturbance White Paper
at 5 (explaining there are standard features for
modern inverters that should be enabled within IBR
plants to better understand their response to grid
events and improve overall fleet performance).
167 See supra note 88.
168 See Order No. 693, 118 FERC ¶ 61,218 at P 188
(in directing NERC to address or consider NOPR
comments, the Commission explained that it ‘‘does
not direct any outcome other than that the
comments receive consideration’’).

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additional IBR data points (e.g.,
telemetry collections or other automated
platform integrations) are needed to
further enhance real-time visibility of
Bulk-Power System operations.
3. Unregistered IBR and IBR–DER Data
Sharing
87. In the NOPR, the Commission
preliminarily found that the currently
effective Reliability Standards do not
ensure that Bulk-Power System planners
and operators receive modeling data and
parameters regarding unregistered IBRs
that, individually or in the aggregate, are
capable of adversely affecting the
reliable operation of the Bulk-Power
System. The Commission also
preliminarily found that the currently
effective Reliability Standards do not
require that Bulk-Power System
planners and operators receive
modeling data and parameters regarding
IBR–DERs that in the aggregate are
capable of adversely affecting the
reliable operation of the Bulk-Power
System. The Commission preliminarily
determined that planning coordinators
and other entities need modeling data
and parameters for both unregistered
IBRs and IBR–DERs in the aggregate to
assure greater accuracy in modeling.169
88. The Commission proposed to
direct NERC to submit new or modified
Reliability Standards addressing IBR
data sharing that require transmission
owners to provide modeling data and
parameters (e.g., steady-state, dynamic,
and short circuit modeling information,
and control settings for momentary
cessation and ramp rates) to appropriate
registered entities (e.g., planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities) for
unregistered IBRs in their transmission
owner areas where unregistered IBRs
individually or in the aggregate
materially affect the reliable operation
of the Bulk-Power System.170 The
Commission similarly proposed to
direct NERC to develop new or modified
IBR data sharing Reliability Standards
that require distribution providers to
provide modeling data and parameters
to appropriate registered entities (e.g.,
planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities) for IBR–DERs in the
aggregate connected in their distribution
provider areas where those IBR–DERs in
the aggregate materially affect the
reliability of the Bulk-Power System and
169 NOPR,

181 FERC ¶ 61,125 at P 79.

are not otherwise subject to compliance
with Reliability Standards.171
89. The Commission stated that this
approach would be similar to that taken
in other Reliability Standards that
require transmission owners and
distribution providers to provide certain
planning and operational data received
from unregistered entities to appropriate
registered entities (e.g., planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities).172
The Commission recognized that, given
the small size and location of many of
the IBR–DERs on the distribution
system, it may not be practical for
distribution providers to provide
modeling data and parameters to model
individual IBR–DERs directly.173 The
Commission instead proposed that the
new or modified Reliability Standards
should permit distribution providers to
provide modeling data and parameters
of IBR–DERs in the aggregate or
equivalent for IBR–DERs interconnected
to their distribution systems (e.g., IBR–
DERs in the aggregate and modeled by
resource type such as wind or solar PV,
or IBR–DERs in the aggregate and
modeled by interconnection
requirements performance to represent
different steady-state and dynamic
behavior) to appropriate registered
entities (i.e., planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities).174
171 Id. (citing NERC, Reliability Guideline:
Parameterization of the DER_A Model, 8–16 (Sept.
2019), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline_DER_
A_Parameterization.pdf (2019 DER_A Model
Guideline) (retired)).
172 Id. P 80 (noting that this approach is
consistent with certain currently effective
Reliability Standards and citing Reliability
Standard IRO–010–2 (Reliability Coordinator Data
Specification and Collection), Requirement R1
(providing that ‘‘[t]he Reliability Coordinator shall
maintain a documented specification for the data
. . . including non-[bulk electric system]
data’’(emphasis added)), Requirement R2
(providing that ‘‘[t]he Reliability Coordinator shall
distribute its data specification to entities’’),
Requirement R3 (providing that ‘‘[e]ach . . .
Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R2
shall satisfy the obligations of the documented
specifications’’); Reliability Standard PRC–006–3
(Automatic Underfrequency Load Shedding),
Requirement R8 (requiring that a UFLS entity, i.e.,
relevant transmission owner and distribution
provider, ‘‘provide data to its Planning
Coordinator(s)’’)). Reliability Standard IRO–010–4
(Reliability Coordinator Data Specification and
Collection) became effective April 1, 2023;
Reliability Standard PRC–006–5 (Automatic
Underfrequency Load Shedding) became effective
April 1, 2021.
173 Id.
174 Id. (citing NERC, Distributed Energy
Resources: Connection Modeling and Reliability

170 Id.

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a. Comments
90. Commenters generally support the
NOPR’s proposed directive to require
transmission owners to collect and
share unregistered IBR data and to
require distribution providers to collect
and share modeling data and parameters
of IBR–DERs in the aggregate.175
However, several commenters raise
concerns that transmission owners and
distribution providers may not be able
to collect all the requested data.176
91. NERC, AEU, IRC, and ISO–NE
support the Commission’s directive to
revise the currently effective Reliability
Standards to require that adequate and
accurate data is available for all BulkPower System-connected resources
(including unregistered IBRs).177 NERC
notes that experience has demonstrated
that, without all of the relevant
protections and controls being modeled
and validated, the resulting
interconnection and long-term planning
studies will not identify possible
performance issues.178 NERC
recommends that if no distribution
provider is registered on a specific
system, the transmission owner should
coordinate with the relevant
transmission planner, planning
coordinator, balancing authority,
transmission operator, and/or reliability
coordinator for developing, submitting,
and validating aggregate DER models
(inclusive of IBR–DER) in planning or
operational studies.179
92. IRC also supports Reliability
Standards that facilitate the provision of
IBR-related data from registered entities
to reliability coordinators, planning
coordinators, and other registered
entities responsible for the safe and
reliable operation of the Bulk-Power
System.180 To ensure the appropriate
data is provided, IRC requests that the
final rule specify the data to be
Considerations, 7 (Feb. 2017), https://
www.nerc.com/comm/Other/essntlrlbl
tysrvcstskfrcDL/Distributed_Energy_Resources_
Report.pdf (NERC DER Report); 2019 DER_A Model
Guideline).
175 See generally NERC Initial Comments at 9;
AEU Initial Comments at 5; ACP/SEIA Initial
Comments at 11–12 (although cautioning against
mandating specific modeling and data submissions
to allow entities to identify and request the data and
modeling that best meets their needs); IRC Initial
Comments at 2–3; ISO–NE Initial Comments at 2;
NYSRC Initial Comments at 2; Ohio FEA Initial
Comments at 2, 9.
176 See AEP Initial Comments at 4; APS Initial
Comments at 4; Trade Associations Initial
Comments at 11–12; and SCE/PG&E Initial
Comments at 10–11.
177 NERC Initial Comments at 9; AEU Initial
Comments at 4, 7; IRC Initial Comments at 2; ISO–
NE Initial Comments at 2.
178 NERC Initial Comments at 13.
179 Id.
180 IRC Initial Comments at 2.

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submitted by all types of IBRs (i.e.,
registered IBRs, unregistered IBRs, and
IBR–DERs in the aggregate) and
transmission devices using similar
technologies.181
93. ISO–NE supports the
Commission’s proposed directive and
asserts that, for smaller IBR–DERs,
distribution providers are in the best
position to provide aggregate models
that include behind-the-meter
resources.182 ISO–NE notes that, in the
absence of this aggregate data, it uses
assumptions based on industry
documents and benchmarking to actual
events, which may not always reflect
the realities of IBRs.183 Ohio FEA
supports the Commission’s proposals
and states that the lack of visibility into
operating assets behind the meter,
including ride through of IBR–DERs, is
an ongoing issue.184
94. AEU states that distribution
providers are best situated to fulfill
Reliability Standard requirements
related to the aggregate impact of IBR–
DERs and cautions against any direct
assignment of responsibility to owners
or operators of individual IBR–DERs.185
95. CAISO, Indicated Trade
Associations, and SPP generally support
the proposed directive but caution that
transmission owners and distribution
providers should only be required to
collect and share information that they
can reasonably obtain, and that certain
data may be difficult to obtain.186
CAISO encourages the Commission to
direct NERC to address the potential
‘‘compliance trap’’ and suggests that if
the Commission is going to shift the
compliance burden to transmission
owners and distribution providers from
the IBR generator owner or operator,
there should be consistent mechanisms
in place for transmission owners and
distribution providers to receive such
information.187
96. APS, AEP, LADWP, and SCE/
PG&E raise concerns with the proposed
directive requiring transmission owners
to collect and share unregistered IBR
data and distribution providers to
collect and share IBR–DER data due to
the lack of mechanisms or leverage in
place to require the provision of the
underlying data from unregistered
181 Id.

at 3.

182 ISO–NE

Reply Comments at 2, 5.
183 ISO–NE Initial Comments at 2.
184 Ohio FEA Initial Comments at 2, 9.
185 AEU Initial Comments at 7.
186 CAISO Initial Comments at 31; Indicated
Trade Associations Initial Comments at 9; SPP
Initial Comments at 2.
187 CAISO Initial Comments at 32, 38.

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entities.188 For example, AEP explains
that it does not have access, as a
transmission owner, to all of the data
necessary to model the behavior of
unregistered IBRs, nor does it have
access, as a distribution provider, to all
the data needed to accurately model
IBR–DERs in the aggregate.189
97. SCE/PG&E contend that it is
inappropriate for NERC to develop new
Reliability Standards that place a
compliance burden on transmission
owners and distribution providers for
unregistered IBRs and IBR–DERs in the
aggregate. SCE/PG&E explain that
transmission owners and distribution
providers would not have the requisite
information to comply with the
Reliability Standards and that the
transmission owners and distribution
providers would need to develop new
procedures and provide oversight and
enforcement for unregistered IBRs and
IBR–DERs. SCE/PG&E further state that
balancing authorities, rather than
transmission owners and/or distribution
providers, should be held responsible
for oversight and enforcement as they
have the greatest visibility into the
operation of IBRs on the grid.190
98. APS suggests alternatives to the
proposed IBR–DER directive. APS has
concerns with the proposal to require
distribution providers to share
information provided by an unregistered
entity because the IBR–DER customer
may be unable or unwilling to provide
the data voluntarily.191 Therefore, APS
recommends that the Commission not
direct NERC to require distribution
providers to collect and share IBR–DER
data, but instead defer to the
stakeholder process during the
standards development process to
determine who will provide the data,
how the aggregate IBR–DER model will
be developed, and how the model will
be validated.192
99. APS and Indicated Trade
Associations oppose a directive
requiring transmission owners and
distribution providers to collect and
share data from unregistered IBRs and
IBR–DERs in the aggregate. Indicated
Trade Associations emphasize that,
while it may be appropriate to specify
the types of data to be submitted, a
registered entity cannot provide data
that the registered entity itself does not
have and has no ability to collect.193
188 APS Initial Comments at 4; AEP Initial
Comments at 2; LADWP Reply Comments at 2; SCE/
PG&E Initial Comments at 6.
189 AEP Initial Comments at 4.
190 SCE/PG&E Initial Comments at 6–7.
191 APS Initial Comments at 4.
192 Id. at 4.
193 Indicated Trade Associations Initial
Comments at 10.

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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations
APS believes that the unregistered IBRs
and IBR–DERs may be unable or
unwilling to provide the data
voluntarily and consistently, and that
transmission owners will have little to
no leverage to compel delivery of data
from the unregistered entities; thus,
these requirements are more effectively
shouldered by the IBR owners.194
Indicated Trade Associations explain
that, in most if not all cases, a
transmission owner or distribution
provider has only the information
provided to it during the
interconnection approval process and
interconnection agreements may not
require the IBRs to provide modeling
data. Indicated Trade Associations
explain that in such a case, transmission
owners and distribution providers may
not have the contractual right to add
requirements to provide data
unilaterally and retroactively. In
addition, Indicated Trade Associations
clarify that some IBR–DERs on the
distribution system interconnect under
utility retail tariffs without a separate
interconnection agreement. Indicated
Trade Associations aver that
transmission owners and distribution
providers should not be held
responsible for an unregistered IBR
owner that does not or cannot provide
the data, and that any directives
regarding unregistered IBR and IBR–
DER data sharing and model validation
should recognize this limitation.195
100. Alternatively, Indicated Trade
Associations propose that the
Commission could either convene a
forum to consider the benefits of
applying the new Reliability Standards
to distribution providers with IBR–DERs
in their footprints, or direct NERC to
submit a study on the challenges for
development and implementation of
those new or modified Reliability
Standards. Indicated Trade Associations
also support NERC’s request for
flexibility in determining appropriate
requirements with respect to collecting
and modeling IBR–DER data. In the
alternative, Indicated Trade
Associations ask the Commission to
limit the obligations shouldered by the
distribution providers to what is
feasible.196
101. Indicated Trade Associations
recommend giving consideration to
collecting data from existing registered
generator owners and operators that also
own some IBR–DERs.197
194 APS

Initial Comments at 4.
Trade Associations Initial
Comments at 10–13.
196 Id. at 9, 12–13.
197 Id. at 2.
195 Indicated

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b. Commission Determination
102. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal,
with modification. Specifically, as
proposed in the NOPR, we direct NERC
to submit to the Commission for
approval one or more new or modified
Reliability Standards that require: (1)
transmission owners to provide to BulkPower System planners and operators
modeling data and parameters for
unregistered IBRs in their transmission
owner areas that, individually or in the
aggregate, materially affect the reliable
operation of the Bulk-Power System and
(2) distribution providers to provide to
Bulk-Power System planners and
operators modeling data and parameters
for IBR–DERs in the aggregate in their
distribution provider areas where the
IBR–DERs in the aggregate materially
affect the reliable operation of the BulkPower System.198
103. However, we find persuasive the
comments explaining that certain data
may be challenging or infeasible for the
transmission owner or distribution
provider to obtain.199 We recognize that
there may be limitations on the ability
of certain transmission owners to
provide all data about unregistered IBRs
that Bulk-Power System transmission
planners and operators may need for the
reliable operation of the Bulk-Power
System. Likewise, there may be
limitations on the ability of certain
distribution providers to provide all
data about IBR–DERs in the aggregate
that Bulk-Power System transmission
planners and operators may need for the
reliable operation of the Bulk-Power
System. We therefore modify the NOPR
proposal, as discussed below.
104. Recognizing that there may be
instances in which transmission owners
are unable to gather adequate
unregistered IBR modeling data and
parameters to create and maintain
unregistered IBR models in their
transmission owner areas, we modify
the NOPR proposal and direct NERC to
develop new or modified Reliability
Standards that require each
198 See supra note 14 (noting that although the
remaining subset of unregistered IBRs and IBR–
DERs in the aggregate will not be subject to the
mandatory and enforceable Reliability Standards set
forth herein, they may be subject to provision of
data and information to their respective
transmission owners and distribution providers, as
applicable, in accordance with their specific
interconnection agreements; and encouraging NERC
to continue its efforts to review and evaluate
whether reliability gaps continue to remain and if
new or modified functional registration categories
or Reliability Standards are necessary).
199 See, e.g., AEP Initial Comments at 2; APS
Initial Comments at 4; Indicated Trade Associations
Initial Comments at 10; SCE/PG&E Initial
Comments at 6, 7.

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transmission owner, if unable to gather
accurate unregistered IBR data or unable
to gather unregistered IBR data at all, to
provide instead to the Bulk-Power
System planners and operators in their
areas: (1) an estimate of the unregistered
IBR modeling data and parameters, (2)
an explanation of the limitations of the
availability of data, (3) an explanation of
the limitations of any data provided by
unregistered IBRs, and (4) the method
used for estimation. We believe that this
directive appropriately balances
commenters’ concerns about data
accessibility and burden with the
established need for transmission
owners to provide unregistered IBR
modeling data and parameters to BulkPower System planners and operators in
their transmission owner area. We
recognize that estimated modeling data
and parameters are approximations of
actual modeling data and parameters.
We further acknowledge that there is
some degree of error in estimated
modeling data and parameters.
However, on balance we believe that
requiring such estimates with
explanation of any limitations is an
improvement from not having any data
at all; and that even estimates will
increase the overall adequacy of models
and improve the reliability of the BulkPower System. To support this data
collection, we further direct NERC to
consider commenters suggestions to
implement a process or mechanism by
which transmission owners would
receive modeling data and
parameters.200
105. We also recognize that there may
be instances where distribution
providers are similarly unable to gather
adequate modeling data and parameters
from IBR–DERs.201 Accordingly, to
account for instances in which
distribution providers are unable to
gather adequate modeling data and
parameters of IBR–DERs to create and
maintain IBR–DER models, we modify
the NOPR proposal and direct NERC to
develop new or modified Reliability
Standards that require that each
distribution provider, if unable to gather
accurate IBR–DERs data in the aggregate
or unable to gather IBR–DERs data in
the aggregate at all, provide instead to
200 See, e.g., AEP Initial Comments at 2; SCE/
PG&E Initial Comments at 6–7.
201 For example, there may be no distribution
providers that meet the NERC Registration Criteria
in a given area (e.g., greater than 75 MW of peak
load directly connected to the bulk-electric system,
facilities that are used in protection systems or
programs for the protection of the bulk-electric
system, etc.), see NERC Rules of Procedure App. 5B
(Statement of Compliance Registry Criteria) 6–7,
(Jan. 19, 2021), https://www.nerc.com/
FilingsOrders/us/RuleOfProcedureDL/
Appendix%205B.pdf.

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the Bulk-Power System planners and
operators in their areas: (1) an estimate
of the modeling data and parameters of
IBR–DERs in the aggregate,202 (2) an
explanation of the limitations of the
availability of data, (3) an explanation of
the limitations of the data provided by
IBR–DERs, and (4) the method used for
estimation. In support of above, we
further direct NERC to consider
commenters’ suggestions to implement a
process or mechanism by which
distribution providers would receive
modeling data and parameters.203
106. Finally, as noted by commenters,
we recognize that there may be
instances where IBR–DERs are
connected to an entity that does not
meet the criteria for registration with
NERC as a distribution provider. For
those areas with IBR–DERs that in the
aggregate materially affect the reliable
operation of the Bulk-Power System but
do not have an associated registered
distribution provider, we direct NERC to
determine the appropriate registered
entity responsible for providing data of
IBR–DERs that in the aggregate have a
material impact on the Bulk-Power
System, or, when unable to gather such
accurate IBR–DERs data, to provide
instead to the Bulk-Power System
planners and operators in their areas: (1)
an estimate of the modeling data and
parameters of IBR–DERs that in the
aggregate have a material impact on the
Bulk-Power System, (2) an explanation
of the limitations of the availability of
data, (3) an explanation of the
limitations of any data provided by the
IBR–DERs that in the aggregate have a
material impact on the Bulk-Power
System, and (4) the method used for
estimation.
107. We believe that requiring
transmission owners and distribution
providers to collect required data for
unregistered IBRs, and IBR–DERs in the
aggregate, will result in greater
consistency than the piecemeal
approach proposed by Indicated Trade
Associations, in which some data for
unregistered IBRs and IBR–DERs in the
aggregate would also be provided by
registered generator owners and
operators. Further, we believe that
transmission owners and distribution
providers are in a better position to
collect and estimate required data for
unregistered IBRs and IBR–DERs in the
aggregate that are directly connected to
their respective areas than balancing
authorities. We anticipate that the need
for estimated data for unregistered IBRs
202 See

supra note 89.
infra P 147 (identifying the EPRI DER
Settings Database as one potential technical source
for IBR–DER estimation data).
203 See

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connected to the Bulk-Power System, as
opposed to actual data, and thus the
burden of collecting such data, will
decrease over time due to the model
provision requirements in the pro forma
LGIP and pro forma SGIP, as adopted in
Order No. 2023,204 and the ongoing
NERC activities to register IBR generator
owners and operators.205 As
transmission providers modify their
interconnection agreements in
compliance with Order No. 2023, we
expect that the need to estimate data
will decrease because validated models
for smaller sized resources will begin to
be submitted to transmission providers
with interconnection requests under the
Commission’s pro forma SGIP. NERC’s
registration of previously unregistered
IBRs should result in more IBRs
providing data and validated models
pursuant to applicable Reliability
Standards.206
108. Regarding CAISO’s concern
regarding the potential ‘‘compliance
trap’’ where planners and operators rely
on third-party data 207 and IRC’s request
that the final rule specify the data to be
submitted by all IBRs (i.e., registered
IBRs, unregistered IBRs, and IBR–DERs
in the aggregate) and transmission
devices using similar technologies, we
direct NERC to determine through its
standards development process the
minimum categories or types of data
that must be provided to transmission
planners, transmission operators,
transmission owners, and distribution
providers necessary to predict the
behavior of all IBRs and to ensure that
compliance obligations are clear.208 As
204 Order No. 2023, 184 FERC ¶ 61,054 at P 1659
(revising Attachment A to Appendix 1 of the pro
forma LGIP and Attachment 2 of the pro forma
SGIP to require each interconnection customer
requesting to interconnect a non-synchronous
generating facility to submit to the transmission
provider specified modeling information).
205 See Order Approving Workplan, 183 FERC
¶ 61,116 at P 1 (approving NERC’s plan to modify
its Rules of Procedure related to registration and to
identify and register IBR generator owners and
operators that fall below the thresholds for the bulkelectric system definition). NERC’s Commission
approved bulk electric system definition is a subset
of the Bulk-Power System and defines the scope of
the Reliability Standards and the entities subject to
NERC compliance. Revisions to Electric Reliability
Org. Definition of Bulk Elec. Sys. & Rules of Proc.,
Order No. 773, 141 FERC ¶ 61,236 (2012), order on
reh’g, Order No. 773–A, (May 17, 2013), 143 FERC
¶ 61,053 (2013), rev’d sub nom. People of the State
of N.Y. v. FERC, 783 F.3d 946 (2d Cir. 2015); NERC
Glossary at 7–9.
206 NERC’s August 16, 2023, Compliance Filing
sets forth NERC’s proposed registration plan
indicating that implementation of the plan will
result in registration of 97.5 percent of Bulk-Power
System connected IBRs of the total IBR nameplate
capacity MWs installed in 2021 of transmission and
sub-transmission IBRs.
207 CAISO Initial Comments at 38.
208 See Order No. 672, 114 FERC ¶ 61,104 at PP
322, 325 (requiring that Reliability Standards be

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discussed in more detail in section IV.C
of this final action, we are also directing
NERC to develop new or modified
Reliability Standards that require the
use of approved industry IBR models
that accurately reflect the behavior of all
IBRs during steady state, short-circuit,
and dynamic conditions. By contrast,
we believe that a directive to task
distribution providers as the appropriate
registered entity to collect and share the
modeling data and parameters of IBR–
DERs in the aggregate is preferable to
deferring to the stakeholder process as
suggested by APS. The distribution
provider, as the entity providing and
operating the lines between the
transmission and distribution
systems,209 is the entity best situated to
have access to the data necessary for
accurate estimation and, other than
Indicated Trade Associations that
suggested the piecemeal approach
already discussed above, no commenter
identified other potential entities as an
equally efficient option.
109. We also decline to either
convene a forum to consider the benefits
of applying the new Reliability
Standards to distribution providers with
IBR–DERs in their footprints, or direct
NERC to submit a study on the
challenges for development and
implementation of those new or
modified Reliability Standards as
suggested by Indicated Trade
Associations. As identified in the NOPR
and expounded upon in this final
action, there is a pressing need to
address the gap posed by the currently
effective Reliability Standards. BulkPower System planners and operators
need to receive modeling data and
parameters regarding IBR–DERs that in
the aggregate are capable of adversely
affecting the reliable operation of the
Bulk-Power System. The additional
process proposed by commenters will
unnecessarily delay resolution of the
identified gap. Further, regarding
various comments suggesting specific
timing for requiring data provision, we
believe that determining when data
would be available and required to be
provided is better addressed during the
standards development process. We
encourage NERC to continue its efforts
to review and evaluate whether
reliability gaps continue to remain and
if new or modified functional
registration categories or Reliability
Standards are necessary to ensure the
reliable operation of the Bulk-Power
System. NERC may choose to revise, or
the Commission may direct further
clear and unambiguous as to what is required and
who is required to comply).
209 See NERC Rules of Procedure, App. 5B at 6.

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revisions to, registration or Reliability
Standards to ensure the provision of
adequate modeling data and parameters
from unregistered IBRs and/or IBR–
DERs in the aggregate.
C. Data and Model Validation
110. In the NOPR, the Commission
preliminarily found that the currently
effective Reliability Standards are
inadequate to ensure that Bulk-Power
System planners and operators: (1) have
the steady state, dynamic, and short
circuit models of the elements that make
up generation, transmission, and
distribution facilities that accurately
reflect the generation resource’s
behavior in steady state and dynamic
conditions; (2) have dynamic models
(i.e., models of equipment that reflect
the equipment’s behavior during various
grid conditions and disturbances) that
accurately represent the dynamic
performance of all generation resources,
including momentary cessation when
applicable; (3) can validate and update
resource models by comparing the
provided data and resulting models
against actual operational behavior to
achieve and maintain accuracy of their
transmission planning and operations
models; and (4) have interconnectionwide models that represent all
generation resources, including: (a)
synchronous generation resource
models; (b) load resource models; and
(c) registered and unregistered IBR
models, as well as IBR–DERs modeled
in the aggregate. The Commission
further stated that Bulk-Power System
planners and operators need accurate
planning, operations, and
interconnection-wide models to ensure
reliable operation of the system.210
111. Therefore, the Commission
proposed to direct NERC to submit to
the Commission for approval one or
more new or modified Reliability
Standards that would ensure that all
necessary models are validated.
Specifically, the Commission proposed
to direct NERC to modify the Reliability
Standards to require: (1) generator
owners to provide validated registered
IBR models to the planning coordinators
for interconnection-wide, planning, and
operations models; (2) transmission
owners to provide validated
unregistered IBR models to the planning
coordinators for interconnection-wide,
planning, and operations models; and
(3) distribution providers to provide
validated models of IBR–DERs in the
aggregate to the planning coordinators
for interconnection-wide, planning, and
operations models. Further, the
Commission proposed that the new or
210 NOPR,

181 FERC ¶ 61,125 at P 82.

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modified Reliability Standards should
require models of individual registered
and unregistered IBRs, as well as IBR–
DERs in the aggregate, to represent the
dynamic behavior of these IBRs at a
sufficient level of fidelity for BulkPower System planners and operators to
perform valid facility interconnection,
planning, and operational studies on a
basis comparable to synchronous
generation resources.211
1. Approved Component Models
112. In the NOPR, the Commission
preliminarily found that without
approved generation models that
accurately reflect generation resource
behavior in steady state and dynamic
conditions, Bulk-Power System
planners and operators are unable to
adequately predict IBR behavior and
their subsequent impact on the BulkPower System.212 The Commission
found that the currently effective
Reliability Standards only refer broadly
to models in Reliability Standard MOD–
032–1, Attachment 1, rather than
requiring the use of NERC’s approved
component models, which would
provide more accurate information
about resource behavior. Thus, the
Commission proposed to direct NERC to
develop new or modified Reliability
Standards that require the use of
approved industry generic library IBR
models that accurately reflect the
behavior of IBRs during both steady
state and dynamic conditions.
113. The Commission elaborated that
NERC could reference its approved
component model list in the Reliability
Standards and require that only those
models be used when developing
planning, operations, and
interconnection-wide models. The
Commission further stated that the
proposed directives were consistent
with the recommendations in the NERC
reports.213
a. Comments
114. AEP, CAISO, ISO–NE, LADWP,
and NYSRC generally support the
proposed directive to require the use of
approved industry generic library IBR
models 214 (e.g., NERC’s approved
211 Id.

P 83.
212 Id. P 86 (citing NERC Standardized Powerflow
Parameters and Dynamics Models).
213 Id.
214 Various commenters reference the type of
transmission power system models used for
transmission steady state and dynamic assessments
with a variety of synonymous names. These
conventional transmission power system simulation
models may be referred to as root mean square
models or positive-sequence models. These
synonymous model names are sometimes used in
combinations and appended to the terms generic or
standardized library models. This final action uses

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74269

model list) instead of user-defined
models.215 As an owner of registered
IBRs, unregistered IBRs, and IBR–DERs,
AEP confirms that transmission owners
and distribution providers need
consistent and accurate data to properly
model IBR behavior.216
115. CAISO supports the use of
approved industry generic library IBR
models but suggests that, instead of the
NERC approved model list, the WECC
models should be used when
developing national standards for model
development and validation.217 CAISO
explains that the WECC models have
been the subject of numerous research
projects undertaken for the purpose of
validating various components and
suggests that NERC and its stakeholders
could use this experience when
developing standards for model
development and validation.218 CAISO
notes that even unregistered IBRs are
required to provide dynamic models
from the manufacturer using the latest
WECC approved dynamic models.219
116. LADWP explains that it is
challenging for transmission providers
to obtain accurate IBR model
information, and often the supplied
modeling data is generic and neither
adequate nor high fidelity.220 NYSRC
supports establishing validation
processes for IBR projects and plant
component models and ensuring that
detailed verifiable models and data are
available for planning and operational
studies.221 NYSRC explains that such
component models may include
individual solar, wind, or storage
devices, plant protection systems, plant
controllers, ancillary equipment, and
interconnection equipment
(transformers and transmission lines).
NYSRC also suggests that the
Commission allow for and consider
making clear in any resulting rules or
requirements that provide for
mandatory delivery by equipment
manufacturers and project developers of
detailed, equipment specific, verifiable
manufacturer’s models and data
necessary for planning and operational
studies.222
the most simplified term ‘‘generic library model’’ to
describe the approved collection of industry
transmission power system models used for steady
state, dynamic, and short-circuit assessments.
215 AEP Initial Comments at 3; CAISO Initial
Comments at 1; ISO–NE Reply Comments at 2–3;
LADWP Reply Comments at 3 NYSRC Initial
Comments at 4.
216 AEP Initial Comments at 3–4.
217 CAISO Initial Comments at 29.
218 Id.
219 Id. at 26.
220 LADWP Reply Comments at 3.
221 NYSRC Initial Comments at 3.
222 Id.

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117. NERC opposes requiring entities
to rely solely on standardized generic
library models because such models
may not be able to fully represent IBR
behaviors.223 Instead, NERC supports
establishing an acceptable model list
that identifies which models to use for
specific types of studies.224 NERC
explains that while user-defined models
have some drawbacks, the Commission
should not preclude their use. NERC
also notes that entities may rely on
different modeling practices or types of
models and, therefore, recommends an
approach that combines: (1) a positive
sequence standard library model; (2) a
positive sequence user-defined model;
(3) a detailed EMT model; and (4) a
model benchmarking report that
compares all models.225 NERC adds that
entities should correctly parameterize
all of these models when performing
benchmarking testing to reflect the asbuilt equipment installed in the field
and include an explanation to the
receiving entity of any limitations with
the models.226
118. Regarding the use of user-defined
models, EPRI states that both generic
library models and user-defined models
are important to use—provided that
both types of models are appropriately
parameterized and validated. EPRI
further explains that user-defined
models may be more accurate in certain
kinds of studies that require unique
controls or protection strategies, which
generic models may not have. EPRI
therefore suggests that the Commission
consider requiring both validated userdefined models and validated generic
library models.227
119. While ACP/SEIA generally
support the Commission’s proposed
directive to require NERC to develop
Reliability Standards that address
modeling of IBRs, they recommend
giving the transmission service provider
the discretion to require user-defined
models, generic library models (with
site-specific parameterization), or
both.228
120. ISO–NE explains that it only
accepts a user-defined model if there is
no generic library model that could be
used.229 ISO–NE explains that it has
found that user-defined models are not
uniform and may conflict with other
user-defined models. Accordingly, ISO–
NE supports the Commission’s proposal
to require the use of approved industry
223 NERC

Initial Comments at 15–16.

224 Id.
225 Id.

at 16.

226 Id.
227 EPRI

Initial Comments at 17.
Initial Comments at 12–13.
229 ISO–NE Reply Comments at 3.
228 ACP/SEIA

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generic library models or, if the
Commission declines to proceed with
the proposed directive, asks that the
final rule either not require the use of
user-defined models or allow entities to
preclude their use.230
121. Although the Commission did
not propose to include directives
addressing EMT models, multiple
commenters suggest that the
Commission include requirements for
EMT models in the final rule.231
b. Commission Determination
122. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop new or
modified Reliability Standards that
require the use of approved industry
generic library IBR models that
accurately reflect the behavior of IBRs
during steady state, short-circuit, and
dynamic conditions when developing
planning, operations, and
interconnection-wide models. For
example, the new or modified
Reliability Standards could reference
the NERC approved component model
list, which defines the models that may
be used, and those models that may not
be used, for specific types of studies.232
This approved component model list
includes WECC’s IBR models. Without
requiring the use of approved industry
generic library models, Bulk-Power
System planners and operators may not
be able to create system models that
adequately predict IBR behaviors and
subsequent impacts on the Bulk-Power
System.233
123. We decline to modify the NOPR
proposal to allow NERC the discretion
to include alternatives to approved
industry generic library models in any
new or modified Reliability Standards,
and we similarly decline to modify the
NOPR proposal to allow transmission
providers the discretion to diverge from
the approved nation-wide component
model list. While Order No. 2023 allows
interconnection customers to submit
novel user-defined models with their
interconnection requests,234 the risks
associated with the use of user-defined
models in the interconnection context
are substantially different than in the
Bulk-Power System operations and
planning context. Specifically,
230 Id.
231 See, e.g., NERC Initial Comments at 13; ACP/
SEIA Initial Comments at 12; SPP Initial Comments
at 3; EPRI Initial Comments at 18; Indicated Trade
Associations Initial Comments at 7 (although also
noting that EMT modeling can be burdensome to
industry); ISO–NE Initial Comments at 2–3.
232 See NERC Standardized Powerflow Parameters
and Dynamics Models.
233 NOPR, 181 FERC ¶ 61,125 at P 36.
234 See Order No. 2023, 184 FERC ¶ 61,054 at P
1660.

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interconnection studies require the
transmission provider to study impacts
from integrating a new resource on their
system; these internal models are not
typically shared or combined with
models from neighboring systems. In
contrast, in the transmission planning
and operations context, planning
coordinators, transmission planners,
transmission operators, and balancing
authorities combine models on both a
regional and interconnection-wide basis
to assess and mitigate impacts from a
number of system conditions and
contingencies on their portion of the
Bulk-Power System. In the event of nonconvergence or other problems with the
model, a user-defined model, if not
appropriately parameterized and not
submitted with open-source code or
dynamic link library and code files, may
not allow internal model components to
be viewed or modified, which would
impede the ability of planning
coordinators, transmission planners,
transmission operators, and balancing
authorities to remediate any issues.
Accordingly, while user-defined models
may be acceptable to an individual
transmission provider when building its
own models and studying its own
system, which we are not prohibiting
here, the use of a standard set of
approved industry generic library
models is essential to creating BulkPower System planning and operations
system models (i.e., combining models
between neighboring entities and for
interconnection-wide models) so that
Bulk-Power System planners and
operators can adequately predict
behaviors and subsequent impacts to the
reliable operation of the Bulk-Power
System.
124. We direct NERC to determine
through its standards development
process which nation-wide approved
component models are needed to build
IBR plant models for steady state, shortcircuit, and dynamics studies. We
acknowledge NERC’s comment that
user-defined models may be helpful for
specific local reliability studies;
however, the user-defined model cannot
be used in place of nation-wide
approved component models for
regional analysis or interconnectionwide analysis because the user-defined
model may cause non-convergence and
other issues.235 However, NERC may
235 See NERC, Libraries of Standardized
Powerflow Parameters and Standardized Dynamics
Models, Ver. 1 at 1 (Oct. 15, 2015), https://
www.nerc.com/comm/PC/Model%20Validation
%20Working%20Group%20MVWG%202013/
NERC%20Standardized%20
Component%20Model%20Manual.pdf (explaining
that since Bulk-Power System planning and
operations system models are constructed using

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allow the submission of user-defined
models alongside the approved industry
generic IBR model. Various entities do
not accept user-defined models or only
accept them for limited instances along
with the open-source code which then
allows internal model components to be
viewed and modified. For example, PJM
does not accept user-defined models
and requires generic models for model
verification in accordance with
currently effective Reliability Standards
MOD–026–1 and MOD–027–1.236
NYISO accepts a user-defined model in
limited instances but requires either the
open-source code (allowing anyone to
access the internal model) or dynamic
link library data and code files
(compiled code that must be
decompiled to view the internal model)
that must be supplied for existing power
flow software and in perpetuity.237
125. Accordingly, we direct NERC to
develop new or modified Reliability
Standards that require the sole use of
nation-wide approved component
generic library models for system
models to facilitate the exchange of
neighboring entities’ respective
planning and operation models and to
build interconnection-wide models. One
example of a way NERC could meet this
directive would be to require an
equivalent generic library model along
with all submissions of user-defined
models so that the generic library model
can be used when combining
neighboring transmission system
models and in interconnection-wide
models.
126. With respect to NERC’s
recommendation for model
thousands of individual component models, there
can be problems when using models that are
proprietary or confidential, because it ‘‘impedes the
free flow of information necessary for
interconnection-wide power system analysis and
model validation.’’ Further, the document
recommends ‘‘an industry-wide forum for
discussing the validity of these various model
structures’’ and that ‘‘industry should agree upon
standardized component model structures and
associated parameters for particular types of
equipment.’’).
236 See PJM, Guidance for NERC MOD–026–027
Generation Owner Preparation & Submittal, 5 (Aug.
28, 2022), https://www.pjm.com/-/media/library/
whitepapers/compliance/20220828-guidance-forgo-to-prepare-nerc-mod-026-027-andsubmittal.ashx (explaining that ‘‘user-defined
models are not acceptable. PJM requires submittal
of generic models with appropriate due diligence
made to closely match unit performance’’).
237 See NYISO, Reliability Analysis Data Manual,
22 (Dec. 2022), https://www.nyiso.com/documents/
20142/2924811/M-24-RAD-Att%20B-v2022-12-07Final.pdf/d91ccb08-d34b-1890-c85a-baa21712d9d4
(explaining that if a user-defined model is provided
then a technical justification must accompany the
model along with the open-source code of the
model; if the open-source code cannot be provided
then all dynamic link library data and code files
must be supplied for existing power flow software
and all future versions of the power flow software).

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benchmarking, we direct NERC to
determine through its standards
development process whether the
development of benchmark cases to test
model performance and a subsequent
report comparing model performance
are needed and at what periodicity.
127. Many commenters request that
the Commission consider requiring the
inclusion of EMT models in the new or
modified Reliability Standards. In Order
No. 2023, the Commission required
interconnection customers to submit
EMT models with their interconnection
requests only if the transmission
provider performs an EMT study as part
of its interconnection study process.238
We decline here, however, to direct
NERC to require EMT models at this
time because EMT models are typically
used to examine the electromagnetic
transient behavior of individual
generation resources and to study plantto-plant interactions. EMT models are
not used to build interconnection-wide
models or perform respective studies
and, as such, requiring their inclusion
would not address the reliability gaps
identified in section III above, which are
the subject of the directives in this final
action. However, we note that NERC has
existing and ongoing Reliability
Standards projects that include EMT
studies,239 and we encourage NERC and
stakeholders to continue working in this
area.
2. Verification of IBR Plant Dynamic
Model Performance
128. In the NOPR, the Commission
proposed to direct NERC to require the
generator owners of registered IBRs and
the transmission owners that have
unregistered IBRs on their systems to
provide dynamic models that accurately
represent the dynamic performance of
facilities of registered IBRs and facilities
of unregistered IBRs, including
momentary cessation and/or tripping,
and all ride through behavior to the
planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities. The Commission further
proposed to direct NERC to require
distribution providers that have IBR–
DERs on their systems to ensure that the
aggregated dynamic models (i.e., plant
models that describe the behaviors of all
IBRs installed and controlled at a single
electrical location) provided to the
planning coordinators, transmission
planners, reliability coordinators,
238 See Order No. 2023, 184 FERC ¶ 61,054 at P
1659.
239 See NERC Initial Comments at 14 (describing
multiple EMT modeling projects including a
taskforce, Reliability Standards Project 2022–04
(EMT Modeling), and a reliability guideline).

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transmission operators, and balancing
authorities accurately represent the
dynamic performance of IBR–DER
facilities in the aggregate, including
momentary cessation and/or tripping,
and all ride through behavior (e.g., IBR–
DERs in the aggregate modeled by
interconnection requirements
performance to represent different
steady-state and dynamic behavior).240
129. In the NOPR, the Commission
noted that the currently effective
Reliability Standards do not require
generator owners to provide verified
models and data for IBR-specific
controls (e.g., power plant central
controller functions and protection
system settings), do not require
transmission owners to provide verified
dynamic models for unregistered IBRs,
and do not require distribution
providers to provide verified dynamic
models for IBR–DERs in the aggregate.
The Commission therefore proposed to
direct NERC to develop new or modified
Reliability Standards that account for
the technological differences between
IBRs and synchronous generation
resources.
a. Comments
130. Commenters generally support
the proposed NOPR directive that the
new or modified Reliability Standards
require that entities verify all IBR
models.241 For example, NERC confirms
that the currently effective Reliability
Standards, such as MOD–026–1 and
MOD–027–1, which pertain to model
verification, could be enhanced by
requiring entities to verify that the
models are of sufficient accuracy and to
make corrections in a timely manner.242
Additionally, NERC states that it has
recommended that the Project 2020–06
(Verifications of Models and Data for
Generators) standard drafting team
employ a more comprehensive model
validation process. This includes
equipment manufacturer engagement
(e.g., by attesting to model quality),
submitting as-built protection and
controls, hardware-in-the-loop testing,
testing/operations data, and considering
future IEEE P2800.2 model validation
and verification procedures.243
240 NOPR,

181 FERC ¶ 61,125 at P 84.
the NOPR and this final action use
‘‘verification’’ to mean the model is properly
parameterized and validated, and ‘‘validation’’ to
mean the confirmation that models reflect real
world operational behaviors, commenters use the
terms verification and validation interchangeably in
their responses.
242 NERC Initial Comments at 12 (stating that
NERC Project 2020–06 (Verifications of Models and
Data for Generators) is already developing revisions
to enhance requirements for model verification).
243 Id. at 17.
241 Although

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131. EPRI supports dynamic model
verification and generally recommends
that the new or modified Reliability
Standards use the precise language and
definitions as published in the industry
standards and aligning requirements
with leading international practice and
grid codes.244 EPRI points to the IEEE
P2800.2 test and verification procedures
currently under development as an
example of how NERC may align with
industry requirements for IBR plant
model verification. Specifically, EPRI
explains that the IEEE P2800.2 working
group is developing a recommended
practice for test and verification
procedures that will include
procedures, criteria, and definitions.245
132. To ensure the appropriate
dynamic model data is provided, IRC
requests that the final rule specify that
the data to be submitted by transmission
devices using similar technologies
include data to study IBR dynamic
behavior (e.g., data for EMT studies).246
Further, IRC suggests including the
equipment testing and field tests as a
part of model validation to show that
the models accurately represent the
equipment as installed in the field. IRC
also recommends including
requirements to model and study IBR
installations to capture certain adverse
control interactions that would be
unseen by IBR owner modeling efforts
but would still create reliability issues
seen by the reliability coordinators,
transmission planners, or planning
authorities.247
133. CAISO supports the proposed
directive to require NERC to ensure that
the new or modified Reliability
Standards account for verification of
IBR plant dynamic model performance.
CAISO emphasizes that the new or
modified Reliability Standards should
include requirements that enable the
registered entities responsible for
planning and operating the Bulk-Power
System to validate data of registered
IBRs and unregistered IBRs and data of
IBR–DERs in the aggregate, by
comparing the provided data and
resulting models with actual
performance and behavior.248
134. NERC, AEU, EPRI, and ACP/
SEIA express concerns about the
availability of verified IBR dynamic
models. EPRI explains that transmission
providers may need to reevaluate or
restudy interconnection requests
Initial Comments at 8.
at 19–20 (referring to IEEE, Test and
Verification of BPS-connected Inverter-Based
Resources, P2800–2, https://sagroups.ieee.org/28002/).
246 IRC Initial Comments at 3.
247 Id. at 4.
248 CAISO Initial Comments at 30.

because site-specific verified plant
models may not be available at the time
of the facility interconnection studies,
and the restudy would therefore create
delays to the generator interconnection
process.249 Further, ACP/SEIA and
LADWP raise concerns with the
timelines for when such model data
should be required. For example, ACP/
SEIA note that as plant settings change,
it may be difficult to provide fully
validated models during the
interconnection process and, therefore,
EMT models should only be required
once equipment details and settings are
final, which occurs at the end of the
interconnection process.250 LADWP
similarly notes the challenge of
obtaining accurate model information if
the interconnection customer has not
actually purchased its equipment for
use in a project.251 NERC and AEU
recommend that the Commission clarify
in the final rule that a registered IBR
would not be subject to the dynamic
model requirements until the facility
has completed the facility
interconnection process and achieved
commercial operation.252 AEU supports
focusing the requirements proposed in
the NOPR on the fidelity of models and
data provided at the completion of the
facility interconnection process and on
the model validation steps that can be
taken following a plant
commissioning.253 ACP/SEIA
recommend that the Commission direct
NERC to develop a process for registered
generators, including IBRs, to provide
validated models to transmission
planners in a reasonable timeframe
following completion of the facility
interconnection process.254
135. ISO–NE requests that the
Commission make clear that generator
owners, transmission owners, and
distribution providers—and not
transmission planners or transmission
operators—should provide validated
models to planning coordinators. ISO–
NE requests that the Commission make
clear that generator owners,
transmission owners, and distribution
providers should provide validated
models to planning coordinators, and
not transmission planners or
transmission operators. ISO–NE and IRC
also request that the Commission state
in the final rule that model validation
should include equipment testing and
field tests that show the models

244 EPRI
245 Id.

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249 EPRI

Initial Comments at 22.
Initial Comments at 12.
251 LADWP Reply Comments at 3.
252 NERC Initial Comments at 12; AEU Initial
Comments at 6.
253 AEU Initial Comments at 6.
254 ACP/SEIA Initial Comments at 13.
250 ACP/SEIA

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accurately represent the equipment and
control settings as installed in the
field.255 Finally, ISO–NE asks the
Commission to direct NERC to add
distribution providers as an applicable
entity for Reliability Standard MOD–
032–1 so planning coordinators and
transmission planners are able to obtain
IBR–DER information.256
136. EPRI also expresses concerns
about model parameterization and
recommends that the Reliability
Standards require generator owners,
transmission owners, and distribution
providers to share verified and
appropriately parameterized
modeling.257
137. NERC, APS, and Indicated Trade
Associations caution that it may be
difficult to verify models for
unregistered IBRs and IBR–DERs in the
aggregate because transmission owners
and distribution providers do not own
the assets they would need to address
and, therefore, flexibility may be
warranted.258 NERC suggests that, in
lieu of mandating that an entity provide
a validated model, the Commission
could require the transmission owner,
distribution provider, transmission
planner, or planning coordinator to
work collaboratively with state
regulators to identify, implement, and
perform an effective model validation
approach for IBR–DERs in the
aggregate.259 Additionally, the planning
coordinator could, as part of system
validation in Reliability Standard MOD–
033–2, work with the distribution
provider, transmission planner,
reliability coordinator, transmission
operator, and balancing authority to
capture disturbance information such
that the representation of IBR–DERs in
the aggregate in their models can be
validated against system
performance.260
138. Indicated Trade Associations and
APS express concerns about distribution
providers verifying models for IBR–
DERs in the aggregate. APS states that
the current method does not account for
distributed energy resource parameters
for running field tests to verify the
accuracy of the model and that field test
methodologies do not exist to verify the
aggregate IBR–DERs at the feeder
level.261 APS asserts that, even if the
distribution providers provide an
255 ISO–NE Initial Comments at 3; IRC Initial
Comments at 4.
256 ISO–NE Initial Comments at 4.
257 EPRI Initial Comments at 12–13.
258 NERC Initial Comments at 32; APS Initial
Comments at 5; Indicated Trade Association Reply
Comments at 2.
259 NERC Initial Comments at 32.
260 Id.
261 APS Initial Comments at 5.

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aggregated approximation based on a
generic model without engaging
manufacturers and solar developers, the
root cause will not be addressed because
distribution providers do not have
sufficient information to create
models.262 Noting that distribution
providers do not have the ability to
monitor whether the individual IBR–
DERs have been altered, APS indicates
that it would be difficult for distribution
providers to know the precise mix of
IBR–DERs when developing aggregate
IBR–DER modeling.
139. SPP expresses concerns with the
types of models that are proposed to be
verified (i.e., regular power flow models
and dynamic models). SPP requests that
the Commission require EMT model
verification because only some IBR
behaviors can be recognized and
evaluated in an EMT study. Specifically,
SPP requests that the Commission direct
NERC to identify all three model types
(power flow, dynamic, and EMT) in new
Reliability Standards as the models that
should be verified.263
b. Commission Determination
140. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop new or
modified Reliability Standards that
require the generator owners of
registered IBRs, transmission owners
that have unregistered IBRs on their
system, and distribution providers that
have IBR–DERs on their system to
provide models that represent the
dynamic behavior of these IBRs at a
sufficient level of fidelity to provide to
Bulk-Power System planners and
operators to perform valid
interconnection-wide, planning, and
operational studies on a basis
comparable to synchronous generation
resources.
141. We also direct NERC to require
the generator owners of registered IBRs
and the transmission owners that have
unregistered IBRs on their system to
provide to the Bulk-Power System
planners and operators (e.g., planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities)
dynamic models that accurately
represent the dynamic performance of
registered and unregistered IBRs,
including momentary cessation and/or
tripping, and all ride through behavior.
Recognizing that there may be instances
in which transmission owners are
unable to gather accurate unregistered
IBR modeling data and parameters to
create and maintain accurate
262 Id.
263 SPP

Initial Comments at 3.

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unregistered IBR dynamic models in
their transmission owner areas, we
modify the NOPR proposal and direct
NERC to develop new or modified
Reliability Standards that require each
transmission owner, if unable to gather
accurate unregistered IBR data or unable
to gather unregistered IBR data at all, to
provide instead to the Bulk-Power
System planners and operators in their
areas, dynamic models of unregistered
IBRs using estimated data in accordance
with this final action’s section IV.B.3
data sharing directives. Further, we
direct NERC to require distribution
providers to provide to the planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities
aggregated dynamic models that
adequately represent the dynamic
performance of IBR–DERs on their
systems that in the aggregate have a
material impact on the Bulk-Power
System, including momentary cessation
and/or tripping, and all ride through
behavior (e.g., IBR–DERs in the
aggregate modeled by interconnection
requirements performance to represent
different steady-state and dynamic
behavior). Recognizing that there may
be instances in which distribution
providers are unable to gather data that
accurately represents IBR–DERs in the
aggregate, we modify the NOPR
proposal and direct NERC to include in
the proposed new or modified
Reliability Standards a requirement that
the distribution provider, if unable to
gather data of IBR–DERs that in the
aggregate have a material impact on the
Bulk-Power System, provide to the
Bulk-Power System planners and
operators (i.e., the data recipients) a
dynamic model using estimated data for
IBR–DERs that in the aggregate have a
material impact on the Bulk-Power
System, in accordance with this final
action’s section IV.B.3 data sharing
directives. Furthermore, we
acknowledge that there may be areas
with IBR–DERs in the aggregate that
materially impact the reliable operation
of the Bulk-Power System but do not
have an associated registered
distribution provider. Therefore, we
modify the NOPR proposal and direct
NERC to determine the appropriate
registered entity responsible for
providing adequate data and parameters
of IBR–DERs that in the aggregate have
a material impact on the Bulk-Power
System, and to identify the registered
entities for coordinating, verifying, and
keeping up to date the respective
dynamic models. Finally, NERC must
ensure that the proposed new or
modified Reliability Standards account

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for the dynamic performance of IBR–
DERs that in the aggregate have a
material impact on the Bulk-Power
System.
142. Regarding ISO–NE’s request, we
decline to direct NERC to require
generator owners, transmission owners,
and distribution providers to provide
validated models to planning
coordinators, and not transmission
planners or transmission operators; we
believe all Bulk-Power System planners
and operators (i.e., planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities)
need validated models. Additionally,
we agree with ISO–NE’s request to
direct NERC to add distribution
providers as an applicable entity for
Reliability Standard MOD–032–1 so
planning coordinators and transmission
planners are able to obtain IBR–DER
information. We believe this is
addressed through directives in section
IV.B.3. that require NERC to submit new
or modified Reliability Standards to
address this issue. We decline to
explicitly direct NERC to make the
modification to Reliability Standard
MOD–032–1 because NERC may address
this concern in an equally efficient and
effective manner.
143. Regarding EPRI’s
recommendation to require
appropriately parameterized plant
models, we agree that the model
verification process of an IBR model
should include steps to ensure that
responsible entities provide both
verified and appropriately
parameterized models.264 Additionally,
we agree with IRC’s recommendation
that the plant model verification process
should include requirements for
equipment to be represented as installed
in the field. While we decline to include
this level of detail in the directive to
NERC, we nonetheless direct NERC to
establish a standard uniform model
verification process. A uniform model
verification process will ensure that all
entities use the same set of minimum
requirements to verify that all
generation resource (i.e., synchronous
and non-synchronous) models are
complete and that the models accurately
represent the dynamic behavior of all
generation resources at a sufficient level
of fidelity for Bulk-Power System
planners and operators to perform valid
interconnection-wide, planning, and
operational studies. Therefore, we direct
NERC to define the model verification
264 We believe that the model verification process
should ensure that the IBR model inputs are
appropriately parameterized as well as confirming
that the in-field equipment behavior is consistent
with model behavior.

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process and to require consistency
among the model verification processes
for existing Reliability Standards (e.g.,
FAC–002, MOD–026, and MOD–027)
and any new or modified Reliability
Standards.265
144. As the Commission indicated in
the NOPR, the DER_A model represents
an appropriate basis on which to
develop new or revised modeling
standards for IBR–DERs.266 In the
NOPR, the Commission referenced the
DER_A model as a potential solution to
address the requirements for
distribution providers to share modeling
data and parameters regarding IBR–
DERs in the aggregate and cited the use
of the DER_A model as a way to
implement the requirement to develop
new or modified Reliability
Standards.267 The DER_A model
represents IBR–DERs in the aggregate
and NERC recommends it as the
approved steady state and dynamic
model.268 WECC and EPRI have verified
and updated the DER_A model 269 to
model IBR–DERs in the aggregate and
have used it to study the potential
impacts of IBR–DERs in the aggregate on
the Bulk-Power System. Since 2016,
NERC has issued six Reliability
Guidelines on the DER_A model.270 For
example, NERC’s 2020 IBR–DER Data
Collection Guideline explains how the
265 We note NERC’s statement that through
Project 2020–06 (Verifications of Models and Data
for Generators), it is already working to develop
revisions to enhance requirements for model
verification under MOD–026 and MOD–027. See
NERC Initial Comments at 12, 17.
266 NOPR, 181 FERC ¶ 61,125 at P 79 n.157, P 80
n.159.
267 Id.
268 See NERC Standardized Powerflow Parameters
and Dynamics Models.
269 See EPRI, The New Aggregated Distributed
Energy Resources (der_a) Model for Transmission
Planning Studies: 2019 Update (Mar. 2019) https://
www.epri.com/research/products/
000000003002015320 (describing the specifications
of the model and presenting the results of the
benchmark tests conducted by EPRI during the
approval process of the model through WECC’s
Modeling and Validation Working Group).
270 The six NERC DER_A model guidelines are:
(1) NERC, Reliability Guideline: Modeling
Distributed Energy Resources in Dynamic Load
Models (Dec. 2016), https://www.nerc.com/comm/
RSTC_Reliability_Guidelines/Reliability_Guideline_
-_Modeling_DER_in_Dynamic_Load_Models_-_
FINAL.pdf (retired); (2) NERC, Reliability Guideline:
Distributed Energy Resources Modeling (Sept.
2017), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline_-_
DER_Modeling_Parameters_-_2017-08-18_-_
FINAL.pdf (retired); (3) 2019 DER_A Model
Guideline; (4) IBR–DER Data Collection Guideline;
(5) NERC, Reliability Guideline: Model Verification
of Aggregate DER Models used in Planning Studies
(Mar. 2021), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline%20_
DER_Model_Verification_of_Aggregate_DER_
Models_used_in_Planning_Studies.pdf (Aggregate
DER Model Verification Guideline); and (6) 2023
DER_A Model Guideline.

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distribution provider may be able to use
publicly available data to provide
estimated aggregate IBR–DER modeling
data and parameters to the Bulk-Power
System planners and operators that they
may in turn use as inputs into the DER_
A model.271
145. NERC has provided transmission
planners and planning coordinators
with guidance on how to perform
varying extents of DER_A model
verification using differing amounts of
estimated and measured data to ensure
the aggregate impacts from the DER_A
model reflects actual Bulk-Power
System disturbance behaviors.272
Further, NERC’s 2023 DER_A Model
Guideline provides transmission
planners and planning coordinators
with a set of recommendations for
developing the parameters for the DER_
A dynamic model, and the
recommendations can also be
extrapolated to transmission operators,
reliability coordinators, and other
entities performing stability simulations
of the Bulk-Power System where an
aggregate representation of DERs (i.e.,
both synchronous resources and IBR–
DERs) is required. This guideline also
provides examples on how the DER_A
model parameters can be modified to
account for a mixture of legacy and
newer IBR–DERs.273
146. Accordingly, we direct NERC to
develop new or modified Reliability
Standards that require the use of the
DER_A model or successor models to
represent the behaviors of IBR–DERs
that in the aggregate have a material
impact on the Bulk-Power System at a
sufficient level of fidelity for BulkPower System planners and operators to
create valid planning and operations
and interconnection-wide models and to
be able to perform respective system
studies. For example, the new or
modified Reliability Standards could
require models of IBR–DERs (i.e., DER_
A model) to adequately reflect the
steady-state and dynamic aggregate
resource performance in both a
transmission area and across the
interconnection. Additionally,
estimated modeling data and parameters
of IBR–DERs that in the aggregate (i.e.,
DER_A model) have a material impact
on the Bulk-Power System could be
used where measured and collected data
is not available. We believe requiring
the DER_A model will address NERC’s
271 IBR–DER Data Collection Guideline, 1–2 n.37
(recommending that distribution providers are the
best suited to provide DER information to
transmission planners and planning coordinators
for modeling purposes).
272 See generally Aggregate DER Model
Verification Guideline.
273 See generally 2023 DER_A Model Guideline.

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request for entities to work
collaboratively with the state regulators
to identify, implement, and perform an
effective model validation approach for
IBR–DERs in the aggregate as opposed to
requiring validated models of IBR–DER
in the aggregate that can have a material
impact on the reliable operation of the
Bulk-Power System.
147. Further, to address commenters’
concerns about situations when
distribution providers are unable to
gather and provide data of IBR–DERs in
the aggregate, we note the existence and
suggest, but decline to direct, the use of
the EPRI DER Settings Database.274 The
EPRI DER Settings Database contains the
full set of configuration parameters that
establish the behavior of DERs arranged
in a single file, a so-called utilityrequired profile, which is easily
exchanged between parties or used
across an entire region. For example,
ISO–NE coordinated with
Massachusetts utilities to establish a
single New England Required Utility
Profile applicable to all DERs in ISO–
NE.275
148. The ability to efficiently store
and exchange DER settings files is
particularly useful to help DER
developers and manufacturers to know
the requirements that exist within each
distribution provider’s service territory.
NERC’s 2023 DER_A Model Guideline
also references the EPRI DER Settings
Database as a solution for readily
exchanging and managing large amounts
of IBR–DER settings used to build
dynamic models.276 We encourage
NERC’s standard drafting team to
consider the EPRI DER Settings
Database as a useful resource in the
standards development process when
developing the necessary data exchange
requirements for IBR–DERs that in the
aggregate have a material impact on the
Bulk-Power System.
274 See EPRI, DER Performance Capability and
Functional Settings Database, Ver. 2.1 (2021),
https://dersettings.epri.com/ (EPRI DER Settings
Database) (a public web-based repository for the
settings that utilities require for interconnection of
DER. The database facilitates multiple DER setting
files, and various metadata, e.g., DER types, IEEE
standard 1547-specified performance categories,
sizes, etc.).
275 See Massachusetts Technical Standards
Review Group, Common Technical Standards
Manual, 16 n.9 (Dec. 22, 2022), https://
www.mass.gov/doc/tsrg-common-guideline-202212-22/download; see also ISO–NE, Default New
England Bulk System Area Settings, 1 (2022),
https://www.mass.gov/doc/draft-in-progressdefault-new-england-bulk-system-area-settingsrequirement/download (as of June 1, 2022, these
ISO–NE requirements apply to all DER applications.
Additionally, DER projects must be compliant with
the latest revision of IEEE–1547–2018 (as amended
by IEEE–1547a–2020)).
276 See 2023 DER_A Model Guideline at 18–19.

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149. We acknowledge NERC’s, AEU’s,
EPRI’s, and ACP/SEIA’s concerns about
the verified IBR dynamic models being
unavailable until completion of the
facility interconnection process;
however, in Order No. 2023 the
Commission rejected a request to afford
interconnection customers an extended
period of time to meet the modeling
requirements.277 Order No. 2023
requires an interconnection customer to
provide the required models within the
deadlines established in the pro forma
LGIP and pro forma SGIP. Pursuant to
those provisions, if the interconnection
customer does not cure such a
deficiency within the 10 business day
cure period, the interconnection request
will be considered withdrawn pursuant
to section 3.7 of the pro forma LGIP and
section 1.3 of the pro forma SGIP. Order
No. 2023 requires that the existing 10
business day cure period be consistently
applied to all interconnection request
deficiencies and that having an
extended cure period for model
deficiencies would potentially
introduce delays in the interconnection
process.278 Therefore, verified IBR
dynamic models should be available
prior to the completion of the facility
interconnection process. Moreover,
although the Reliability Standards will
apply to a different (albeit overlapping)
set of entities than Order No. 2023, we
believe consistency is needed between
the complimentary proceedings and
therefore direct NERC to include in the
new or modified Reliability Standards a
similar model verification process
timeline consistent with Order No. 2023
modeling deadline requirements.
150. Regarding the IRC and SPP
concerns about EMT model data
availability and verification, as we
decline to require the use of EMT
models (as explained in section IV.C.1),
we also decline to direct NERC to
explicitly require EMT data and verified
EMT models for the same reasons.
3. Validating and Updating System
Models
151. In the NOPR, the Commission
explained that, after all IBR models are
verified, Bulk-Power System planners
and operators must validate and update
transmission system models by
comparing the provided data and
resulting system models against actual
system operational behavior. The
Commission added that, while
Reliability Standard MOD–033–2
requires data validation of the
interconnection-wide model, the
Reliability Standards lack clarity as to
277 Order

No. 2023, 184 FERC ¶ 61,054 at P 1666.

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whether models of registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate are required to represent the
real-world behavior of the equipment
installed in the field.279
152. The Commission therefore
proposed to direct NERC to develop
new or modified Reliability Standards
that require planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities to validate,
coordinate, and update in a timely
manner the verified data and models of
registered IBRs, unregistered IBRs, and
IBR–DERs by comparing their data and
resulting models against actual
operational behavior. Further, the NOPR
proposed this validation, coordination,
and update directive to achieve and
maintain necessary system models that
accurately reflect performance and
behaviors of registered IBRs and
unregistered IBRs individually and in
the aggregate, as well as performance
and behaviors of IBR–DERs in the
aggregate.280
a. Comments
153. NERC, NYSRC, CAISO, and AEP
support the proposed directive for
planning coordinators, transmission
planners, reliability coordinators,
transmission operators, and balancing
authorities to validate, coordinate, and
update transmission planning and
transmission operations system
models.281 NERC explains that its
experience has shown that
interconnection and long-term planning
studies cannot identify possible
performance issues without ‘‘all of the
relevant protections and controls being
modeled and validated.’’ 282 ACP/SEIA
explains that new models and
validation should not be required for
modifications that do not reflect any
material electrical performance
impact.283
154. NERC agrees that transmission
planners, planning coordinators, and
reliability coordinators should have
planning and operations models that
represent all generation resources,
including registered and unregistered
IBRs, as well as aggregate representation
279 NOPR,

181 FERC ¶ 61,125 at P 40.
P 85.
281 NERC Initial Comments at 10; NYSRC Initial
Comments at 1; CAISO Initial Comments at 30; AEP
Initial Comments at 3.
282 NERC Initial Comments at 13 (citing NERC
and Texas RE, March 2022 Panhandle Wind
Disturbance Report (Aug. 2022), https://
www.nerc.com/pa/rrm/ea/Documents/Panhandle_
Wind_Disturbance_Report.pdf (Panhandle
Disturbance Report) (covering the Texas Panhandle
event (March 22, 2022)); Odessa 2022 Disturbance
Report).
283 ACP/SEIA Initial Comments at 14.
280 Id.

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74275

of distributed energy resources (both
synchronous and IBR).284 NERC
explains that it has a number of projects
underway in this area, including Project
2020–06 (Verifications of Models and
Data for Generators) and Project 2022–
04 (EMT Modeling). NERC states that
additional projects may be needed for
clarity and model accuracy in the
future, including projects to address
Commission directives included in a
final rule in this proceeding. NERC
explains that it is also planning to issue
a modeling-focused NERC Alert by the
end of 2023 to better understand the
extent of condition of modeling issues,
which could inform future standards
development efforts.285
155. CAISO agrees that Bulk-Power
System planners and operators need
accurate planning and operational
information so that their own models,
together with the interconnection-wide
models, reflect how IBRs operate in real
world scenarios.286 APS asserts, similar
to its comments regarding the
difficulties of verifying models for IBR–
DERs in the aggregate, that there is no
feasible method (i.e., comparing actual
to simulated events in a systematic way)
to validate IBR–DER models system
wide.287 In comparison, CAISO asserts
that stakeholders could address the
challenge of modeling IBR–DERs in the
aggregate.288
b. Commission Determination
156. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to submit new or
modified Reliability Standards that
require Bulk-Power System planners
and operators to validate, coordinate,
and update in a timely manner the
system models by comparing all
generator owner, transmission owner,
and distribution provider verified IBR
models (i.e., models of registered IBRs,
unregistered IBRs, and IBR–DERs that in
the aggregate have a material impact on
the Bulk-Power System) and resulting
system models against actual system
operational behavior. NERC may
implement this directive by modifying
Reliability Standards MOD–026 and
MOD–027 or by developing new
Reliability Standards to establish
requirements mandating a process to
validate and keep up to date the system
models. We find that this directive
addresses ACP/SEIA’s concerns
comments regarding modification to and
validation of models that do not reflect
284 Id.

at 10.
Initial Comments at 11.
286 CAISO Initial Comments at 33.
287 APS Initial Comments at 5.
288 CAISO Initial Comments at 35–36.
285 NERC

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any material electrical performance
impact.
157. We believe the development of
new or modified Reliability Standards is
an important corollary to NERC’s
ongoing effort to identify and register
generator owners and operators of IBRs.
Although NERC’s registration changes
will not at this time address IBR–DERs
that in the aggregate have a material
impact on the Bulk-Power System, we
believe APS’s concerns regarding
system-wide model validation is
addressed in NERC’s Reliability
Guidelines 289 and through the use of
the EPRI DER Settings Database. We
recognize that some distribution
providers may not be able to provide a
precise set of modeling data and
parameters that accurately represent
IBR–DERs in the aggregate. For these
situations, NERC has provided a
technical means to estimate in aggregate
the needed IBR–DER modeling data and
parameters (i.e., for the DER_A model)
in the IBR–DER Data Collection
Guideline.290 Further, NERC’s 2021
Aggregate DER Model Verification
Guideline provides transmission
planners and planning coordinators
with tools and techniques that can be
adapted for their specific systems to
verify that aggregate DER models (i.e.
DER_A models) are a suitable
representation of these resources in
planning assessments.291 Furthermore,
for those areas with IBR–DERs in the
aggregate that materially impact the
reliable operation of the Bulk-Power
System but do not have an associated
registered distribution provider, we
modify the NOPR proposal to direct
NERC to determine the appropriate
registered entity responsible for the data
and parameters of IBR–DERs in the
aggregate and to establish a process that
requires identified registered entities to
coordinate, validate, and keep up to
date the system models.
4. Need for Coordination When Creating
and Updating Planning, Operational,
and Interconnection-Wide Data and
Models
158. In the NOPR, the Commission
preliminarily found that there is a
‘‘coordination gap’’ among registered
entities that build and verify
interconnection-wide models. The
Commission noted that the functional
entities and designees specified in
Reliability Standards MOD–032–1 and
289 See generally IBR–DER Data Collection
Guideline; Aggregate DER Model Verification
Guideline.
290 See generally IBR–DER Data Collection
Guideline.
291 See generally Aggregate DER Model
Verification Guideline.

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MOD–033–2 are not required to work
collaboratively to create
interconnection-wide models that
accurately reflect real-world
interconnection-wide IBR performance
and behavior. Therefore, the
Commission proposed to direct NERC to
develop new or modified Reliability
Standards that require planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities to
validate, coordinate, and keep up to
date in a timely manner the verified
data and models of registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate by comparing their data and
resulting models against actual
operational behavior to achieve and
maintain necessary modeling accuracy
of individual and aggregate (1)
registered IBR performance and
behaviors and (2) unregistered IBR
performance and behaviors, as well as
performance and behaviors of IBR–DERs
in the aggregate.292
a. Comments
159. NERC, CAISO, and AEP support
the directives proposed in the NOPR
that would require planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities to
coordinate when creating and updating
planning, operations, and
interconnection-wide models.293 For
example, NERC agrees that there is a
need for closer ties and coordination for
Reliability Standards MOD–032 and
MOD–033 activities to require that the
models are tested more regularly and
any modifications or updates to these
models are provided to the relevant
entities responsible for planning and
operating the Bulk-Power System.294
Further, NERC states that Reliability
Standards MOD–032 and MOD–033
should be updated to require a more
comprehensive practice for system
model validation requiring models to be
rigorously tested for deficiencies and
include minimum requirements for
benchmarking events, such as by
including a requirement that all plant
models be validated through Reliability
Standard MOD–033 activities.295
160. CAISO supports the NOPR
proposal and notes that, while there are
technical, administrative, and
compliance burdens associated with the
imposition of additional new or
modified IBR Reliability Standards, this
181 FERC ¶ 61,125 at PP 84–85.
Initial Comments at 14; CAISO Initial
Comments at 33; AEP Initial Comments at 1.
294 NERC Initial Comments at 14.
295 Id. at 14–15.

initiative will provide a forum to
consider ways to achieve an efficient
and effective exchange of information
among all relevant NERC-registered
entities.296
b. Commission Determination
161. Pursuant to section 215(d)(5) of
the FPA, we modify the NOPR proposal
to provide additional specificity to
explain coordination and keep up to
date in a timely manner the verified
data and models of registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate in the system models.297
Specifically, we direct NERC to develop
new or modified Reliability Standards
that require planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities to establish
for each interconnection a uniform
framework with modeling criteria, a
registered modeling designee, and
necessary data exchange requirements
both between themselves and with the
generator owners, transmission owners,
and distribution providers to coordinate
the creation of transmission planning,
operations, and interconnection-wide
models (i.e., system models) and the
validation of each respective system
model. Further, we direct NERC to
include in the new or modified
Reliability Standards a requirement for
generator owners, transmission owners,
and distribution providers to regularly
update and communicate the verified
data and models of registered IBRs,
unregistered IBRs, and IBR–DERs by
comparing their resulting models
against actual operational behavior to
achieve and maintain necessary
modeling accuracy for inclusion of these
resources in the system models. For
those areas with IBR–DERs in the
aggregate that have a material impact on
the reliable operation of the Bulk-Power
System but do not have an associated
registered distribution provider, we
modify the NOPR proposal to direct
NERC to determine the appropriate
registered entity responsible for the
models of those IBR–DERs and to
determine the registered entities
responsible for updating, verifying, and
coordinating models for IBR–DERs in
the aggregate to meet the system models
directives. NERC may implement this
directive by modifying Reliability
Standards MOD–032–1 and MOD–033–
2 or by developing new Reliability
Standards to establish requirements
mandating an annual 298 process to

292 NOPR,
293 NERC

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296 CAISO

Initial Comments at 31–32.
181 FERC ¶ 61,125 at P 85.
298 See Reliability Standard MOD–032–1 at 15
(explaining that ‘‘presently, the Eastern/Quebec and
297 NOPR,

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coordinate, validate, and keep up-todate the transmission planning,
operations, and interconnection-wide
models.

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D. Planning and Operational Studies
162. In the NOPR, the Commission
preliminarily found that the currently
effective Reliability Standards do not
adequately require planning and
operational studies to: (1) assess
performance and behavior of both
individual and aggregate registered IBRs
and unregistered IBRs, as well as IBR–
DERs that in the aggregate have a
material impact on the Bulk-Power
System; (2) have and use validated
modeling and operational data for
individual registered IBRs and
unregistered IBRs, as well as modeling
and operational data of IBR–DERs that
in the aggregate have a material impact
on the Bulk-Power System; and (3)
account for the impacts of registered
and unregistered IBRs individually and
in the aggregate, as well as IBR–DERs
that in the aggregate have a material
impact on the Bulk-Power System,
within and across planning and
operational boundaries for normal
operations and contingency event
conditions. The Commission stated that
planning and operational studies must
use validated IBR modeling and
operational data so that studies account
for the actual behavior of both registered
and unregistered IBRs individually and
in the aggregate, as well as IBR–DERs
that in the aggregate have a material
impact on the Bulk-Power System.299
163. The Commission preliminarily
found that the currently effective
Reliability Standards do not result in
accurate planning studies of Bulk-Power
System performance over a broad
spectrum of system conditions and
following a wide range of probable
contingencies that includes all
resources.300 The Commission observed
that inaccurate planning assessments
may lead to false expectations that
system performance requirements are
met and may inadvertently mask
potential reliability risks in planning
and operations.301 The Commission
proposed to direct NERC to submit for
approval one or more new or modified
Reliability Standards that would require
planning coordinators and transmission
Texas Interconnections build seasonal cases on an
annual basis, while the Western Interconnection
builds cases on a continuous basis throughout the
year’’).
299 NOPR, 181 FERC ¶ 61,125 at P 87.
300 Id. P 88.
301 See NERC Glossary at 23 (defining planning
assessment as a ‘‘Documented evaluation of future
Transmission System performance and Corrective
Action Plans to remedy identified deficiencies.’’).

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planners to include in their planning
assessments the study and evaluation of
performance and behavior of registered
and unregistered IBRs individually and
in the aggregate, and IBR–DERs in the
aggregate, under normal and
contingency system conditions in their
planning area. The Commission further
proposed that the planning assessments
include the study and evaluation of the
ride through performance (e.g., tripping
and momentary cessation conditions) of
such IBRs in their planning area for
stability studies on a comparable basis
to synchronous generation resources.302
164. The Commission stated that the
proposed new or modified Reliability
Standards should also require planning
coordinators and transmission planners
to consider the behavior of registered
and unregistered IBRs individually and
in the aggregate, as well as IBR–DERs in
the aggregate, using planning models of
their area and using interconnectionwide area planning models. Further, the
Commission stated that the proposed
new or modified Reliability Standards
should also require planning
coordinators and transmission planners
to consider all IBR behaviors in adjacent
and other planning areas that adversely
impact a planning coordinator’s or
transmission planner’s area during a
disturbance event. The Commission
explained that this is needed because
registered IBRs, unregistered IBRs, and
IBR–DERs tend to act in the aggregate
over a wide area during such an
event.303
165. The Commission preliminarily
found that the Reliability Standards also
do not require that the various
operational studies (including
operational planning analyses,304 realtime monitoring, real-time
302 NOPR,

181 FERC ¶ 61,125 at P 88.
(citing 2021 Solar PV Disturbances Report
at v; Odessa 2021 Disturbance Report at v; NERC,
1,200 MW Fault Induced Solar Photovoltaic
Resource Interruption Disturbance Report, 2 (June
2017), https://www.nerc.com/pa/rrm/ea/1200_MW_
Fault_Induced_Solar_Photovoltaic_Resource_/
1200_MW_Fault_Induced_Solar_Photovoltaic_
Resource_Interruption_Final.pdf (Blue Cut Fire
Event Report) (covering the Blue Cut Fire event
(August 16, 2016))); see also NOPR, 181 FERC
¶ 61,125 at P 88.
304 NERC defines operational planning analysis as
an ‘‘evaluation of projected system conditions to
assess anticipated (pre-Contingency) and potential
(post-Contingency) conditions for next-day
operations.’’ The definition goes on to explain that
the evaluation shall reflect ‘‘applicable inputs
including, but not limited to, load forecasts;
generation output levels; Interchange; known
Protection System and Special Protection System
status or degradation; Transmission outages;
generator outages; Facility Ratings; and identified
phase angle and equipment limitations.
(Operational Planning Analysis may be provided
through internal systems or through third-party
services).’’ NERC Glossary at 22.
303 Id.

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74277

assessments,305 and other analysis
functions) include all resources to
adequately assess the performance of
the Bulk-Power System for normal and
contingency conditions.306 The
Commission proposed to direct NERC to
submit to the Commission for approval
one or more new or modified Reliability
Standards that would require reliability
coordinators and transmission operators
to include the performance and
behavior of registered and unregistered
IBRs both individually and in the
aggregate, and IBR–DERs in the
aggregate, (e.g., IBRs tripping or entering
momentary cessation individually or in
the aggregate) in their operational
planning analysis, real-time monitoring,
and real-time assessments, including
non-bulk electric system data and
external power system network data
identified in their data specifications.307
166. The Commission further
proposed to direct NERC to submit to
the Commission for approval one or
more new or modified Reliability
Standards that would require balancing
authorities to include the performance
and behavior of registered and
unregistered IBRs individually and in
the aggregate, as well as IBR–DERs that
in the aggregate have a material impact
on the Bulk-Power System, (e.g.,
resources tripping or entering
momentary cessation individually or in
the aggregate) in their operational
analysis functions and real-time
monitoring.308 The Commission
explained that this proposal is
consistent with the recommendations in
the NERC DER Report, IBR Performance
Guideline, IBR–DER Data Collection
Guideline, and Loss of Solar Resources
Alert II. The Commission stated that
these reports indicate that a significant
number of IBRs that have been involved
in system disturbances were not
adequately modeled in interconnectionwide models and tools used to study the
performance and behavior of registered
and unregistered IBRs individually and
305 NERC defines real-time assessment as an
‘‘evaluation of system conditions using Real-time
data to assess existing (pre-Contingency) and
potential (post-Contingency) operating conditions.’’
The definition goes on to explain that the
assessment shall reflect ‘‘applicable inputs
including, but not limited to: load, generation
output levels, known Protection System and Special
Protection System status or degradation,
Transmission outages, generator outages,
Interchange, Facility Ratings, and identified phase
angle and equipment limitations. (Real-time
Assessment may be provided through internal
systems or through third-party services).’’ Id. at 25.
306 NOPR, 181 FERC ¶ 61,125 at P 89.
307 Id. (citing Reliability Standard IRO–010–4,
Requirement R1, pt. 1.1 and Reliability Standard
TOP–003–5, Requirement R1, pt. 1.1.).
308 Id. (citing Reliability Standard TOP–003–5,
Requirement R2, pt. 2.1.).

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in the aggregate, as well as IBR–DERs in
the aggregate. Thus, the Commission
found that neighboring operators may be
unaware that faults in one operator’s
area can trigger controls actions and trip
IBRs in another operator’s area.309

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1. Comments
167. Commenters generally support a
directive to require planning authorities
to include data within their planning
assessments to reflect expected actions
of registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate,
under normal and contingency system
conditions.310 NERC also supports the
proposed Commission directive to
require transmission planners and
planning coordinators to coordinate
their studies with neighboring entities
so that accurate models of registered
and unregistered IBRs, as well as IBR–
DERs in the aggregate, are represented
appropriately for the operating
conditions under study.311
168. NERC expects that any standard
development project to address such a
directive would need to include a wider
set of operating conditions than simply
‘‘peak’’ and ‘‘off-peak’’ conditions.
NERC explains that using production
cost models or other simulation
methods to identify operating
conditions that could result in extreme
stress on the grid could help inform
planning assessments.312
169. NERC highlights that there may
be gaps in the currently effective
Reliability Standard TPL–001–5.1
planning assessments if they are
performed without accurate IBR models
and studies. NERC also points to its
Project 2022–02 (Modifications to TPL–
001–5.1 and MOD–032–1) as addressing
some issues regarding appropriate
inclusion of IBRs and DERs (IBR–DERs
and synchronous DERs) in planning
assessments but notes that additional
modifications may be required to
adequately address the issues presented
in the NOPR. NERC also suggests
enhancing the directive by identifying a
wider set of operating conditions that
would result in the most extreme
expected grid stress conditions, both
during on-peak load conditions but also
off-peak, high renewables conditions
(e.g., low inertia).313
309 Id.

P 89.
e.g., NERC Initial Comments at 18–20;
AEP Initial Comments at 3; LADWP Reply
Comments at 4; NYSRC Initial Comments at 2;
infiniRel Initial Comments at 2; CAISO initial
Comments at 36; IRC initial Comments at 4; ISO–
NE Initial Comments at 3–4.
311 NERC Initial Comments at 19.
312 Id. at 18.
313 Id. at 18–19.
310 See,

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170. Indicated Trade Associations
note that NERC has several ongoing
projects to improve the assessments of
IBR performance as examples of the
ongoing work to address IBR-related
reliability concerns that should inform
the NERC standard drafting teams that
will work to address the directives in
the final rule, once issued, including
Project 2021–04 (Modifications to
Reliability Standard PRC–002) and
Project 2022–02 (Modifications to
Reliability Standards TPL–001–5.1 and
MOD–032–1). Indicated Trade
Associations state that Project 2021–04
would modify disturbance monitoring
and reporting requirements to better
assess resource performance of IBRs
during disturbances, and Project 2022–
02 is intended to clarify how IBRs are
modeled and studied in planning
assessments and to include distribution
system IBR–DER data and models in
steady state and stability contingency
analysis.314
171. LADWP generally supports
including registered and unregistered
IBRs in planning assessments, as well as
assessments of IBR performance under
normal and contingency system
conditions, as critical to ensuring the
reliable operation of the Bulk-Power
System because during disturbance
events IBRs tend to act in the aggregate
over a widespread area. LADWP also
supports including the study and
evaluation of ride through performance
for stability studies on a comparable
basis to synchronous generation
resources.315 LADWP offers that NERC
could create a standardized method and
criteria for performing additional
performance and behavior analysis.316
172. IRC supports directives for
planning and operational studies,
asserting that the current standards do
not grant them authority to require
relevant entities to provide IBR-related
data sufficient for accurate planning or
operational studies.317 SPP encourages
the Commission to ensure that
registered IBRs provide evidence that
they are included in planning
coordinator and transmission planner
planning assessments.318
173. Commenters also support the
Commission’s proposed directive to
require operational authorities to
include data within their operational
studies to reflect expected actions of
registered and unregistered IBRs
individually and in the aggregate, as
314 Indicated Trade Associations Initial
Comments at 7.
315 LADWP Reply Comments at 4.
316 Id. at 4.
317 IRC Initial Comments at 5.
318 SPP Initial Comments at 5.

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well as IBR–DERs in the aggregate,
under normal and contingency system
conditions.319 NERC supports
coordinating models used by balancing
authorities, transmission operators, and
reliability coordinators across their
footprints so that faults in one area do
not result in unexpected tripping issues
in another area.320
2. Commission Determination
174. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop and submit
to the Commission for approval new or
modified Reliability Standards that
require planning coordinators and
transmission planners to include in
their planning assessments the study
and evaluation of performance and
behavior of registered and unregistered
IBRs individually and in the aggregate,
as well as IBR–DERs in the aggregate,
under normal and contingency system
conditions in their planning area. These
Reliability Standards should require
planning coordinators and transmission
planners to include in their planning
assessments the study and evaluation of
the ride through performance (e.g.,
tripping and momentary cessation
conditions) of IBRs in their planning
area for stability studies on a
comparable basis to synchronous
generation resources. The new or
modified Reliability Standards should
also require planning coordinators and
transmission planners to study the BulkPower System reliability impacts of
registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate, in
their planning models of their area and
in their interconnection-wide area
planning models. Further, the new or
modified Reliability Standards should
also require planning coordinators and
transmission planners to study the BulkPower System reliability impacts of
registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs in the aggregate, in
adjacent and other planning areas that
adversely impacts a planning
coordinator’s or transmission planner’s
area during a disturbance event.
175. Regarding NERC’s
recommendations to clarify the types of
steady-state and dynamic grid
conditions to include in planning
studies, we agree that it is important to
ensure performance during periods of
grid stress. Accordingly, we direct
319 NERC Initial Comments at 7; AEP Initial
Comments at 3; NYSRC Initial Comments at 2;
infiniRel Initial Comments at 2; CAISO Initial
Comments at 37; IRC Initial Comments at 4; ISO–
NE Reply Comments at 3.
320 NERC Initial Comments at 20.

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NERC to consider in its standards
development process whether to
include in new or modified Reliability
Standards a requirement that planning
coordinators and transmission planners
include a wide set of grid stress
performance conditions (i.e., both
typical and extreme conditions) in
planning assessments.321 Likewise, with
regards to NERC’s comments related to
on-peak and off-peak studies, we direct
NERC to consider in the standards
development process whether to require
planning coordinators and transmission
planners to account in planning
assessments for both on-peak and offpeak conditions, normal and abnormal
(contingency) conditions with high
penetration levels of IBRs (i.e.,
registered IBRs, unregistered IBRs, and
IBR–DERs that in the aggregate have a
material impact on the Bulk-Power
System), and normal and abnormal
conditions with low inertia. While we
agree with NERC that the above
suggestions have merit, we believe that
vetting in the standards development
process is preferable to determine
whether such provisions are beneficial
and the scope and language of such
provisions. Accordingly, we simply
direct NERC to consider these matters
without directing a specific outcome.
176. We adopt the NOPR proposal
and direct NERC to submit to the
Commission for approval one or more
new or modified Reliability Standards
that require reliability coordinators and
transmission operators to include the
performance and behavior of registered
and unregistered IBRs individually and
in the aggregate, as well as IBR–DERs in
the aggregate, (e.g., IBRs tripping or
entering momentary cessation
individually or in the aggregate) in their
operational planning analyses, real-time
monitoring, and real-time assessments,
including non-bulk electric system data
and external power system network data
identified in their data specifications.322
Further, we agree with commenters and
direct NERC to submit to the
Commission for approval new or
modified Reliability Standards requiring
reliability coordinators and

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321 NOPR,

181 FERC ¶ 61,125 at P 88 & n.164
(citing several NERC disturbance reports that
identifies the potential adverse impact of registered
IBRs, unregistered IBRs, and IBR–DERs acting in the
aggregate in various system conditions over a wide
area).
322 See, e.g., Reliability Standard IRO–010–4,
Requirement R1, pt. 1.1 (stating ‘‘[a] list of data and
information needed by the Reliability Coordinator
to support its Operational Planning Analyses, Realtime monitoring, and Real-time Assessments. . .’’)
and Reliability Standard TOP–003–5, Requirement
R1, pt. 1.1 (stating ‘‘[a] list of data and information
needed by the Transmission Operator to support its
Operational Planning Analyses, Real-time
monitoring, and Real-time Assessments . . . ’’).

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transmission operators, when
performing operational studies, as well
as operational planning analyses, realtime monitoring, real-time assessments,
and other analyses, to include in these
studies all generation resources (i.e., all
generation resources including all IBRs)
necessary to adequately assess the
performance of the Bulk-Power System
for normal and contingency
conditions.323
177. We adopt the NOPR proposal
and direct NERC to submit to the
Commission for approval one or more
new or modified Reliability Standards
that require balancing authorities to
include the performance and behavior
of registered and unregistered IBRs
individually and in the aggregate, as
well as IBR–DERs that in the aggregate
have a material impact on the BulkPower System, (e.g., resources tripping
or entering momentary cessation
individually or in the aggregate) in their
operational analysis functions and realtime monitoring to support the reliable
operation of the Bulk-Power System
during normal and contingency
conditions.324
E. Performance Requirements
1. Registered IBR Frequency and Voltage
Ride Through Requirements
178. In the NOPR, the Commission
preliminarily found that the Reliability
Standards should require registered
IBRs to ride through system
disturbances to support essential
reliability services.325 Without the
availability of essential reliability
services, the Commission explained that
the system would experience instability,
voltage collapse, or uncontrolled
separation. Therefore, the Commission
proposed to direct NERC to develop
new or modified Reliability Standards
that would require registered IBR
facilities to ride through system
frequency and voltage disturbances
where technologically feasible. The
Commission stated that ride through
performance during system disturbances
is necessary for registered IBRs to
support essential reliability services.
179. The Commission proposed that
the new or modified Reliability
Standards should require registered
IBRs to continue to produce power and
perform frequency support during
system disturbances. The Commission
proposed to direct NERC to develop
323 NOPR,

181 FERC ¶ 61,125 at P 52.
e.g., Reliability Standard TOP–003–5,
Requirement R2, part 2.1 (stating ‘‘[a] list of data
and information needed by the Balancing Authority
to support its analysis functions and Real-time
monitoring’’).
325 NOPR, 181 FERC ¶ 61,125 at P 90.
324 See,

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new or modified Reliability Standards
that would require IBR generator owners
and operators to use appropriate settings
(i.e., inverter, plant controller, and
protection) that: (1) will assure
frequency ride through during system
disturbances and that would permit IBR
tripping only to protect the IBR
equipment; and (2) allow for voltage
ride through during system disturbances
and would permit IBR tripping only
when necessary to protect the IBR
equipment.326 In the NOPR, the
Commission also explained that any
new or modified Reliability Standards
should require generator owners of IBR
facilities to prohibit momentary
cessation in the no-trip zone during
disturbances by using appropriate and
coordinated protection and controls
settings.327
180. The Commission proposed to
direct NERC to develop new or modified
Reliability Standards that clearly
address and document the technical
capabilities of, and differences between,
registered IBRs and synchronous
generation resources so that registered
IBRs will support these essential
reliability services.328
a. Comments
181. Commenters generally support
the Commission’s proposed directives to
require IBRs to use appropriate settings
that will assure ride through during
system disturbances.329 NERC supports
the development of a comprehensive,
performance-based ride through
standard to assure future grid
reliability.330 Indicated Trade
Associations and APS agree that the
current Reliability Standards do not
have IBR-specific performance
requirements necessary to ensure the
reliable operation of the Bulk-Power
System.331 IRC asserts that there should
be requirements for all IBRs to act to
support Bulk-Power System reliability
during disturbances.332 AEU highlights
the ability of IBRs to deliver ancillary
services such as frequency control.333
CAISO encourages the Commission to
move forward in directing NERC to
326 Id.

PP 93–95.
P 94.
328 Id. P 90.
329 NERC, AEU, ACP/SEIA, AEP, CAISO,
Indicated Trade Associations, ISO–NE, IRC,
NYSRC, Ohio FEA, SCE/PG&E, and SPP all
indicated support for Reliability Standards for IBR
performance requirements.
330 NERC Initial Comments at 21.
331 Indicated Trade Associations Initial
Comments at 4–5; APS Initial Comments at 2
(indicating it largely supports Indicated Trade
Associations Initial Comments but providing
additional comments on specific topics).
332 IRC Initial Comments at 5.
333 AEU Initial Comments at 2.
327 Id.

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establish a minimum standard to require
all IBRs to ride through frequency
disturbances 334 and states that, in its
experience, modern inverters can meet
these standards without substantial
costs or hardships.335
182. NERC, ACP/SEIA, Indicated
Trade Associations, SCE/PG&E, and SPP
all point to NERC Project 2020–02
(Modifications to PRC–024 (Generator
Ride-through)) as the best means to
address ride through performance of
IBRs. NERC explains that it has already
updated the scope of its existing Project
2020–02 to require ride through
performance for all generation resources
(not just IBRs).336 ACP/SEIA, SPP, and
Indicated Trade Associations note that
this project is addressing performance
standards for all resource types,
including IBRs.337 SCE/PG&E explain
that Project 2020–02 aims to reduce the
type of abnormal performance reliability
impacts to the Bulk-Power System that
NERC has described in its disturbance
reports.338
183. ACP/SEIA agree with the
Commission’s prioritization to require
NERC to develop IBR ride through
Reliability Standards proposed in the
NOPR, although they caution that,
depending on local factors, different
transmission operators may require
different ride through performance of
generators.339 ACP/SEIA recommend
that NERC continue with Project 2020–
02 to modify Reliability Standard PRC–
024–3 so that it becomes a ride through
performance standard for both IBR and
synchronous resources, which would
both save time and provide a
technology-neutral solution in
addressing the full scope of the ride
through risk facing the Bulk-Power
System.340 ACP/SEIA also ask the
Commission to clarify in the final rule
that the new or modified Reliability
Standards on ride through should not
require generators to maintain real
power output at pre-disturbance levels,
noting that it is neither feasible nor
desirable for generators to maintain real
power output at pre-disturbance levels
in many instances. ACP/SEIA suggest
that the directive instead require
334 CAISO

Initial Comments at 11.
at 7 (citing Cal. Indep. Sys. Operator Corp.,
168 FERC ¶ 61,003, at P 18 n.23 (2019) (noting that,
based on input from developers and manufacturers
of IBRs, ‘‘CAISO believes that the cost of meeting
these requirements will be de minimis’’).
336 See, e.g., NERC Initial Comments at 22.
337 ACP/SEIA Initial Comments at 7–8; SPP Initial
Comments at 6; Indicated Trade Associations Initial
Comments at 8.
338 SCE/PG&E Initial Comments at 5.
339 ACP/SEIA Initial Comments at 1–2.
340 Id. at 10–11.

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registered IBRs to continue to inject
current during system disturbances.341
184. EPRI notes that maintaining
current at the pre-disturbance level
during a disturbance may not be
practical, needed, or aligned with IEEE
2800–2022 or other international
requirements.342 EPRI explains that
Commission directives to NERC to
develop Reliability Standards for IBR
ride-through capability and performance
requirements could refer to IEEE 2800–
2022 standards in accordance with good
utility practice as examples of technical
minimum requirements.343
185. NERC supports the Commission’s
proposed directive to require frequency
and voltage ride through during system
disturbances.344 NERC explains that its
updated scope for Project 2020–02 will
require ride through performance for all
generation resources and will include:
(1) no momentary cessation in the no
trip zone specified, (2) no tripping on
instantaneous frequency and voltage
deviations, (3) no tripping due to phase
lock loop loss within acceptable
bounds, (4) no tripping due to DC bus
protection and overcurrent protection,
and (5) no tripping for unbalanced
faults.345 AEU states that IBRs are not
only capable of delivering voltage
regulation but, in some cases, can
provide ancillary services ‘‘more
quickly and accurately than
conventional technologies.’’ 346
186. Indicated Trade Associations
point to NERC Project 2021–02
Modifications to VAR–002–4.1
(Generator Operation for Maintaining
Network Voltage Schedules) as an
existing standards project that is
working to modify the currently
effective Reliability Standard to specify
and ensure the reactive support and
voltage control obligations of IBRs in
accordance with their capability.347
ISO–NE notes that if the Commission
restricts its directive to only registered
IBR generator owners and operators, it
will leave out the majority of IBRs
within New England.348
187. UNIFI notes that newer
technologies such as grid-forming IBRs
have different behavioral responses to
disturbances on the grid and offers an
initial set of specifications for gridforming IBRs that could be used as
uniform technical requirements for the

interconnection, integration, and
interoperability of grid-forming IBRs.349
188. ACP/SEIA recommend that the
Commission direct NERC to either
exempt existing equipment that cannot
meet the new or modified Reliability
Standards or specify that the new or
modified Reliability Standards should
require compliance only to the extent it
is possible with the equipment’s current
capabilities. ACP/SEIA suggest that any
exemption should cover generators that
cannot meet the ride-through
requirements with updates to their
inverter and control settings, and thus
would require replacement of that
equipment. ACP/SEIA point to
Reliability Standard PRC–024–3 as an
example of an exemption that is already
included.350
189. CAISO recommends that the
Commission support NERC in
identifying technical changes or
equipment modifications that could be
made to existing IBRs incapable of
disabling momentary cessation, such as
eliminating plant-level controller
interactions.351 NYSRC disagrees that
there should be an exception for
existing IBRs and recommends that the
Commission delineate an amount of
time for IBR facilities to either
demonstrate compliance or institute
their own mitigation measures.352
NYSRC and ISO–NE ask the
Commission to clarify that the
performance requirements directed as
part of the final rule would apply to
both new and existing IBRs.353
b. Commission Determination
190. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop new or
modified Reliability Standards that
require registered IBR generator owners
and operators to use appropriate settings
(i.e., inverter, plant controller, and
protection) to ride through frequency
and voltage system disturbances and
that permit IBR tripping only to protect
the IBR equipment in scenarios similar
to when synchronous generation
resources use tripping as protection
from internal faults. The new or
modified Reliability Standards must
require registered IBRs to continue to
inject current and perform frequency
349 UNIFI

341 Id.

at 7.
342 EPRI Initial Comments at 25.
343 Id. at 5.
344 NERC Initial Comments at 22.
345 Id.
346 AEU Initial Comments at 3.
347 Indicated Trade Associations Initial
Comments at 8.
348 ISO–NE Initial Comments at 5.

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Initial Comments at 1.
Initial Comments at 9. See also id.
at 8 (Reliability Standard PRC–024–3, Requirement
R3 requires generator owners to document each
known regulatory or equipment limitation that
prevents the resource from meeting protection
settings criteria).
351 CAISO Initial Comments at 17 (quoting 2021
Solar PV Disturbances Report at 14).
352 NYSRC Initial Comments at 4.
353 Id.; ISO–NE Initial Comments at 6.
350 ACP/SEIA

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support during a Bulk-Power System
disturbance. Any new or modified
Reliability Standard must also require
registered IBR generator owners and
operators to prohibit momentary
cessation in the no-trip zone during
disturbances. NERC must submit new or
modified Reliability Standards that
establish IBR performance requirements,
including requirements addressing
frequency and voltage ride through,
post-disturbance ramp rates, phase lock
loop synchronization, and other known
causes of IBR tripping or momentary
cessation.354 This directive is supported
by the comments, as well as the
recommendations from multiple event
reports, including the Blue Cut Fire
Event Report,355 the Odessa 2021
Disturbance Report,356 and the 2021
Solar PV Disturbances Report.357 The
directive is also consistent with NERC’s
comments and the March 2023 Alert
language.358 Additionally, in response
to requests by ISO–NE and NYSRC for
the Commission to clarify that the
performance requirements directed as
part of the final rule would apply to
both new and existing IBRs, we further
clarify that all performance requirement
directives apply to new and existing
registered IBRs.
191. In response to ACP/SEIA’s
comments, we clarify that we are not
directing NERC to modify the currently
effective Reliability Standards to require
registered IBRs to maintain real power
output during system disturbances.
Rather, the new or modified Reliability
Standards must require registered IBRs
to continue to inject current during
system disturbances. We note that Order
No. 2023 requires non-synchronous
resources to ensure that, within any
physical limitations of the generating
facility, its control and protection
settings are configured or set to
‘‘continue active power production
during disturbance and post disturbance
periods at pre-disturbance levels unless
providing primary frequency response
or fast frequency response’’ 359 The ride
through directive in this final action
differs from the ride-through
requirements established in Order No.
2023 because the Reliability Standards
apply more comprehensively and are
354 See

infra P 209.
Cut Fire Event Report at 11–13.
2021 Disturbance Report at vii, 12–13.
357 2021 Solar PV Disturbances Report at vii, 15,
31.
358 March 2023 Alert at 4–5 (recommending that
industry set fault ride through parameters ‘‘to
maximize active current delivery during the fault
and post-fault periods’’ and to ‘‘not artificially limit
dynamic reactive power capability delivered to the
point of interconnection during normal operations
and [Bulk-Power System] disturbances.’’).
359 Order No. 2023, 184 FERC ¶ 61,054 at P 1715.
355 Blue

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enforced differently. While ride through
requirements set forth in Reliability
Standards will apply to both existing
IBRs and newly interconnecting IBRs,
the ride through requirements of the pro
forma LGIA and pro forma SGIA
established in Order No. 2023 apply
only to newly interconnecting IBRs.
Moreover, any ride through
requirements established through the
Reliability Standards would be
enforceable by NERC, its Registered
Entities, and the Commission through
the Reliability Standard enforcement
process.
192. We believe that, through its
standard development process, NERC is
best positioned, with input from
stakeholders to determine specific IBRs
performance requirements during ride
through conditions, such as type (e.g.,
real current and/or reactive current) and
magnitude of current. NERC should use
its discretion to determine the
appropriate technical requirements
needed to ensure frequency and voltage
ride through by registered IBRs during
its standards development process. In
response to comments regarding NERC
Project 2020–02 Modifications to PRC–
024 (Generator Ride-through) and its
updated scope to address IBR ride
through performance,360 we discuss this
suggestion further in section IV.F,
which requires that NERC’s
informational filing discuss how it is
considering standard development
projects already underway that may
satisfy the directives in this final action.
193. Regarding ACP/SEIA’s request
for an explicit exemption for existing
IBRs with equipment limitations, we
agree that a subset of existing registered
IBRs—typically older IBR technology
with hardware that needs to be
physically replaced and whose settings
and configurations cannot be modified
using software updates—may be unable
to implement the voltage ride though
performance requirements directed
herein. Therefore, we direct NERC
through its standard development
process to determine whether the new
or modified Reliability Standards
should provide for a limited and
documented exemption for certain
registered IBRs from voltage ride
through performance requirements. Any
such exemption should be only for
voltage ride-through performance for
those existing IBRs that are unable to
modify their coordinated protection and
control settings to meet the
requirements without physical
modification of the IBRs’ equipment.
360 See, e.g., NERC Initial Comments at 22;
Indicated Trades Associations Initial Comments at
8.

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Further, we direct NERC to ensure that
any such exemption would be
applicable for only existing equipment
that is unable to meet voltage ridethrough performance. When such
existing equipment is replaced, the
exemption would no longer apply, and
the new equipment must comply with
the appropriate IBR performance
requirements specified in the Reliability
Standards (e.g., voltage and frequency
ride through, phase lock loop, ramp
rates, etc.). The concern that there are
existing registered IBRs unable to meet
voltage ride through requirements
should diminish over time as legacy
IBRs are replaced with or upgraded to
newer IBR technology that does not
require such accommodation.361 We
encourage NERC’s standard drafting
team to consider currently effective
Reliability Standard PRC–024–3,
Requirement R3 as an example for
establishing registered IBR technology
exemptions.362 Finally, we direct NERC,
through its standard development
process, to require the limited and
documented exemption list (i.e., IBR
generator owner and operator
exemptions) to be communicated with
their respective Bulk-Power System
planners and operators (e.g., the IBR
generator owner’s or operator’s planning
coordinator, transmission planner,
reliability coordinator, transmission
operator, and balancing authority). The
Bulk-Power System planners and
operators’ mitigation activity directives
are discussed below in section IV.E.2.
194. In response to ISO–NE’s concern
that applying ride through performance
requirements only to registered IBRs
means that the requirements would not
apply to the vast majority of IBR
capacity in New England, the
Commission has already directed NERC
to register IBRs that materially impact
reliability and believes that NERC’s
workplan approved in the Order
Approving Workplan will be a step
towards mitigating ISO–NE’s concern
about unregistered IBRs.363
195. Although EPRI asserts that IEEE
standards specify technical minimum
361 See generally 2021 Solar PV Disturbances
Report at 14 (discussing momentary cessation from
legacy facilities that cannot eliminate its use).
362 Reliability Standard PRC–024–3, Requirement
R3 (explaining that ‘‘each Generator Owner shall
document each known regulatory or equipment
limitation that prevents an applicable generating
resource(s) with frequency or voltage protection
from meeting the protection setting criteria in
Requirements R1 or R2, including (but not limited
to) study results, experience from an actual event,
or manufacturer’s advice.’’).
363 See Order Approving Workplan, 183 FERC
¶ 61,116 at P 32 (explaining that NERC asserts that
its work plan would result in approximately 98
percent of Bulk-Power System-connected IBRs
being subject to applicable Reliability Standards).

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capability and performance
requirements that could be referenced as
examples of good utility practice,364
NERC’s comments indicate that
currently effective Reliability Standard
PRC–024–3, as well as the re-scoped
Project 2020–02 (Modifications to PRC–
024 (Generator Ride-through)), differ
from IEEE standards in that both the
currently effective Reliability Standard
and re-scoped PRC–024 project disallow
momentary cessation within the no trip
zone, while IEEE–2800–2022 would
allow momentary cessation under
certain conditions.365 As the record in
this proceeding provides no basis to
conclude that the performance
requirements of IEEE 2800–2022 are
preferable to NERC’s or would
adequately address the reliability
concerns discussed in this final action,
we decline to direct NERC to
specifically reference IEEE standards in
its new or modified Reliability
Standards. Rather, NERC has the
discretion to consider during its
standards development process whether
and how to reference IEEE standards in
the new or modified Reliability
Standards.

allowing an exception for legacy
registered IBRs would mean that
transmission owners and operators
would be responsible for mitigating an
event consisting of an unknown number
of IBRs disconnecting from the system
at any time in the future, in an
unanticipated manner.368 NYSRC
asserts that requiring transmission
planners and operators to ensure there
are mitigation strategies for scenarios
where existing IBRs are unable to meet
performance requirements would be
infeasible, as they would need to plan
for and address an event consisting of
an unknown number of IBRs
disconnecting at any time.369
198. Indicated Trade Associations
disagree with the Commission’s
proposal to require transmission
planners and operators to mitigate
instances in which IBRs are incapable of
prohibiting momentary cessation in the
no-trip zone during disturbances,
asserting that such a requirement should
be solely the responsibility of registered
generator owners.370 Indicated Trade
Associations also ask the Commission to
clarify what it means by an ‘‘operator’’
being responsible for mitigating events.

2. Bulk-Power System Planners and
Operators Voltage Ride Through
Mitigation Activities
196. In the NOPR, the Commission
acknowledged that some registered
generator owners and operators of IBRs
currently in operation may be unable to
prohibit momentary cessation in the notrip zone during disturbances by using
appropriate and coordinated protection
and controls settings.366 For such
scenarios, the Commission proposed to
direct NERC to require Bulk-Power
System planners and operators to
implement mitigation activities that
may be needed to address any reliability
impact to the Bulk-Power System posed
by these existing facilities.367

b. Commission Determination

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a. Comments
197. NYSRC raises concerns with the
Commission’s proposal because
364 See, e.g., EPRI Initial Comments at 5; see also
id. at 8 (proposing generally that the Reliability
Standards should consider using the precise
language and definitions as published in the
industry standards and aligning requirements with
leading international practice and grid codes).
365 See NERC Initial Comments at 22 n.39
(explaining that ‘‘[a] notable caveat is that IEEE
2800 allows momentary cessation (referred to as
current blocking) at very low voltages (i.e., <0.1 pu
voltage). This nuance could be addressed by the
standard drafting team and should be considered by
regulatory bodies to ensure alignment.’’).
366 See, e.g., 2021 Solar PV Disturbances Report
at 14 (discussing technical limitations of legacy
IBRs related to voltage control and momentary
cessation).
367 NOPR, 181 FERC ¶ 61,125 at PP 94–95.

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199. Pursuant to section 215(d)(5) of
the FPA, we modify the NOPR proposal.
To the extent NERC determines that a
limited and documented exemption for
those registered IBRs currently in
operation and unable to meet voltage
ride-through requirements is
appropriate due to their inability to
modify their coordinated protection and
control settings,371 we direct NERC to
develop new or modified Reliability
Standards to mitigate the reliability
impacts to the Bulk-Power System of
such an exemption. As NERC will
consider the reliability impacts to the
Bulk-Power System caused by an such
exemption, we believe that the concerns
raised by NYSRC and Indicated Trade
Associations on the appropriate
registered entity responsible for
implementing the mitigation activities,
and the nature of such mitigation,
should be addressed in the NERC
standards development process.
3. Post-Disturbance IBR Ramp Rate
Interactions and Phase Lock Loop
Synchronization
200. In the NOPR, the Commission
proposed to direct NERC to develop
new or modified Reliability Standards
368 NYSRC

Initial Comments at 4.

369 Id.
370 Indicated Trade Associations Initial
Comments at 8.
371 See supra section IV.E.1.

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to address other registered IBR
performance and operational
characteristics that can affect the
reliable operation of the Bulk-Power
System, namely, ramp rate interactions
and phase lock loop synchronization.372
The Commission stated that the
proposed directives would improve the
reliable operation of the Bulk-Power
System by helping to avoid instability,
voltage collapse, uncontrolled
separation, or islanding.373
201. The Commission proposed to
direct NERC to ensure that postdisturbance ramp rates for registered
IBRs are not restricted or do not
artificially interfere with the IBR
returning to a pre-disturbance output
level in a quick and stable manner after
a Bulk-Power System fault event.374
Furthermore, the Commission proposed
to direct NERC to require that IBRs ride
through any conditions not addressed
by the proposed new or modified
Reliability Standards covering
frequency or voltage ride through,
including phase lock loop loss of
synchronism.375
202. Further, the Commission
proposed to direct that the Reliability
Standards obligate generator owners to
communicate to the relevant planning
coordinators, transmission planners,
reliability coordinators, transmission
operators, and balancing authorities the
actual post-disturbance ramp rates and
the ramp rates set to meet expected
dispatch levels (i.e., generation-load
balance). The Commission explained
that the proposed new or modified
Reliability Standards should account for
the technical differences between IBRs
and synchronous generation resources,
such as IBRs’ faster control capability to
372 NOPR,

181 FERC ¶ 61,125 at P 91.
P 92.
374 Id. P 96. See Canyon 2 Fire Event Report at
11 (stating that ‘‘[e]xisting inverters where
momentary cessation cannot be effectively
eliminated should not be impeded from restoring
current injection following momentary cessation.
Active current injection should not be restricted by
a plant-level controller or other slow ramp rate
limits. Resources with this interaction should
remediate the issue in close coordination with their
[balancing authority] and inverter manufacturers to
ensure that ramp rates are still enabled
appropriately to control gen-load balance but not
applied to restoring output following momentary
cessation.’’).
375 Id. P 97. See Canyon 2 Fire Event Report at
vi (explaining that inverters should ride through
momentary loss of synchronism during Bulk-Power
System events, such as faults. Inverters riding
through these disturbances should ‘‘continue to
inject current into the grid and, at a minimum, lock
the [phase lock loop] to the last synchronized point
and continue injecting current to the [Bulk-Power
System] at that calculated phase until the [phase
lock loop] can regain synchronism upon fault
clearing’’).
373 Id.

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ramp power output down or up when
capacity is available.376
203. The Commission also explained
that the currently effective Reliability
Standards do not require that all
generation resources maintain voltage
phase angle synchronization with the
Bulk-Power System grid voltage during
a system disturbance.377 The
Commission proposed that any new or
modified Reliability Standards should
require IBRs to ride through momentary
loss of synchronism during Bulk-Power
System disturbances and require IBRs to
continue to inject current into the BulkPower System at pre-disturbance levels
during a disturbance.378
a. Comments
204. NERC, AEP, CAISO, IRC, and
NYSRC support the proposed directive
to address post-disturbance IBR ramp
rate interactions and phase lock loop
synchronization.379 NERC explains that
it is considering requirements amending
the project scope for Project 2020–02
Modifications to PRC–024 (Generator
Ride-through) to include consideration
of post-fault recovery times, ramp rate
interactions, or the injection of certain
levels of currents (and powers) during
grid disturbances, and to include
requirements that disallow phase lock
loop loss of synchronism and other
phase angle-based tripping within
acceptable bounds.380
205. ACP/SEIA do not believe that
IBRs can inject current accurately when
synchronism is lost and assert that in
those cases IBRs would blindly provide
pre-fault current, which would not be
desirable for grid stability.381 ACP/SEIA
recommend revising the language of the
directive to require generators to
maintain synchronism where possible
and continue to inject current to support
system stability.382
206. Although SPP agrees with
proposed directives related to ramp rate
interactions and phase lock loop
synchronization, SPP requests that the
Commission include in the final rule a
consideration of the IEEE 2800–2022
standard. SPP recommends that the
Commission direct an analysis of the
interrelationship or overlap between the
IEEE standards and any new or
modified Reliability Standards.383
376 NOPR,

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377 Id.

181 FERC ¶ 61,125 at P 96.
P 97.

378 Id.
379 NERC Initial Comments at 5; AEP Initial
Comments at 5; CAISO Initial Comments at 1; IRC
Initial Comments at 5; NYSRC Initial Comments at
1.
380 NERC Initial Comments at 22.
381 ACP/SEIA Initial Comments at 8.
382 Id.
383 SPP Initial Comments at 4.

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207. EPRI suggests that the
Commission direct NERC to develop
new or modified Reliability Standards
using comprehensive and holistic ride
through capability and performance
requirements instead of explicitly
mentioning causes of trip (i.e., loss of
phase lock loop synchronism in this
case) or causes of slow recovery (i.e.,
slow ramp rate), which may leave out
other causes.384
b. Commission Determination
208. Pursuant to section 215(d)(5) of
the FPA, we adopt the NOPR proposal
and direct NERC to develop and submit
to the Commission for approval new or
modified Reliability Standards that
require post-disturbance ramp rates for
registered IBRs to be unrestricted and
not programmed to artificially interfere
with the resource returning to a predisturbance output level in a quick and
stable manner after a Bulk-Power
System disturbance event. The proposed
Reliability Standards must account for
the technical differences between
registered IBRs and synchronous
generation resources, such as registered
IBRs’ faster control capability to ramp
power output down or up when
capacity is available.385 Further, the
Reliability Standards must require
generator owners to communicate to the
relevant planning coordinators,
transmission planners, reliability
coordinators, transmission operators,
and balancing authorities the actual
post-disturbance ramp rates and the
ramp rates to meet expected dispatch
levels (i.e., generation-load balance).
209. We direct NERC to submit to the
Commission for approval new or
modified Reliability Standards that
would require registered IBRs to ride
through any conditions not addressed
by the proposed new or modified
Reliability Standards that address
frequency or voltage ride through,
including phase lock loop loss of
synchronism. The proposed new or
modified Reliability Standards must
require registered IBRs to ride through
momentary loss of synchronism during
Bulk-Power System disturbances and
require registered IBRs to continue to
inject current into the Bulk-Power
System at pre-disturbance levels during
a disturbance, consistent with the IBR
Interconnection Requirements
Guideline and Canyon 2 Fire Event
Report recommendations.386 Related to
384 EPRI

Initial Comments at 25.
181 FERC ¶ 61,125 at P 96.
386 Id. P 97; see also Canyon 2 Fire Event Report
at 20 (recommending that ‘‘[i]nverters should not
trip for momentary [phase lock loop] loss of
synchronism caused by phase jumps, distortion,
etc., during [Bulk-Power System] grid events (e.g.,
385 NOPR,

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ACP/SEIA’s comment recommending to
revise the directive to require generators
to maintain synchronism where possible
and continue to inject current to support
system stability, we direct NERC,
through its standard development
process, to consider whether there are
conditions that may limit generators to
maintain synchronism.
210. Regarding NERC’s comment
informing that NERC is considering
whether to amend the Project 2020–02
Modifications to PRC–024 (Generator
Ride-through) scope, while NERC did
not request any particular Commission
action, we support such project
modification as consistent with our
above directive that registered IBRs ride
through any conditions, including phase
lock loop loss of synchronism.
Similarly, we believe that EPRI’s
suggestion to use comprehensive and
holistic ride through capability and
performance requirements instead of a
piecemeal approach to addressing
performance concerns that may exclude
other ride through capability and
performance requirements aligns with
our above directive.
211. Related to SPP’s comment to
include in the final rule consideration of
IEEE 2800–2022 to address ramp rate
interactions and phase lock loop
synchronization of registered IBRs, we
decline to direct NERC to specifically
reference IEEE standards in its new or
modified Reliability Standards for
similar reasons as discussed above in
section IV.E.1. Rather, NERC has the
discretion to consider during its
standards development process whether
and how to reference IEEE standards in
the new or modified Reliability
Standards. As discussed in section IV.F
below, NERC’s informational filing
should discuss how it is considering
standard development projects already
underway to meet the directives in this
final action.
F. Informational Filing and Reliability
Standard Development Timeline
212. In the NOPR, the Commission
proposed to direct NERC to submit a
compliance filing within 90 days of the
effective date of the final rule in this
proceeding. The proposed compliance
filing would include a detailed,
comprehensive standards development
and implementation plan explaining
how NERC will prioritize the
development and implementation of
faults). Inverters should continue to inject current
into the grid and, at a minimum, lock the [phase
lock loop] to the last synchronized point and
continue injecting current to the [Bulk-Power
System] at that calculated phase until the [phase
lock loop] can regain synchronism upon fault
clearing.’’).

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new or modified Reliability Standards.
The Commission proposed requiring
NERC to explain in its compliance filing
how it is prioritizing its IBR Reliability
Standard projects to meet the directives
in the final rule, taking into account the
risks posed to the reliability of the BulkPower System, standard development
projects already underway, resource
constraints, and other factors as
necessary.387
213. The Commission proposed to
direct NERC to use a staggered approach
that would result in NERC submitting
new or modified Reliability Standards
in three stages: (1) new or modified
Reliability Standards including
directives related to registered IBR
failures to ride through frequency and
voltage variations during normally
cleared Bulk-Power System faults filed
with the Commission within 12 months
of Commission approval of the plan; (2)
new or modified Reliability Standards
addressing the interconnected directives
related to registered IBR, unregistered
IBR, and IBR–DER data sharing;
registered IBR disturbance monitoring
data sharing; registered IBR,
unregistered IBR, and IBR–DER data and
model validation; and registered IBR,
unregistered IBR, and IBR–DER
planning and operational studies filed
with the Commission within 24 months
of Commission approval of the plan;
and (3) new or modified Reliability
Standards including the remaining
directives for post-disturbance ramp
rates and phase lock loop
synchronization filed with the
Commission within 36 months of
Commission approval of the plan.388
1. Comments
214. NERC supports a directive to
require a compliance filing within 90
days.389 NERC generally supports the
Commission’s proposal for a compliance
filing, including a standards
development plan.390 Nevertheless,
NERC seeks clarification of the
Commission’s use of ‘‘implementation
plan’’ and whether that phrase refers to
the timeline for developing responsive
new or modified Reliability Standards
or the timeline for entity
implementation of the approved new or
modified Reliability Standards. NERC
cautions that if implementation plan
means ‘‘the time for an entity to
implement a new or revised Reliability
Standard,’’ then it would be unable to
provide meaningful information for
Reliability Standards still in
387 Id.

P 72.
P 73.
389 NERC Initial Comments at 23.
390 Id.
388 Id.

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development because reasonable
implementation periods are still under
consideration through NERC’s
Commission-approved Reliability
Standard development process.391
215. Indicated Trade Associations
suggest directing NERC to include in its
work plan a comparison to its ongoing
IBR-related standards projects’ scopes
and how each relates to the directives in
the final rule.392 Indicated Trade
Associations caution against losing the
work already completed.393 Indicated
Trade Associations and IRC point to
existing NERC projects addressing
reliability gaps pertaining to IBR data
sharing that could be leveraged to
address the proposed directives,
including Project 2020–06 (Verifications
of Models and Data for Generators),
Project 2022–02 (Modifications to
Reliability Standards TPL–001–5.1 and
MOD–032–1), and Project 2021–04
(Modifications to Reliability Standard
PRC–002–2).394
216. SCE/PG&E, while broadly
supportive of the Commission’s goals,
recommend initiating a pilot program as
a first step before progressing to
directives for new or modified
Reliability Standards. SCE/PG&E
recommend that the pilot program
should study: (1) changes by the CAISO
to address IBRs and consider whether
they translate to national standards; (2)
interconnection tariff revisions under
review at the California Public Utilities
Commission under California Electric
Rule 21; and (3) systems with high-IBR
penetrations and what information is
available to distribution providers,
generator owners, generator operators,
transmission owners, and transmission
operators within these footprints.395
SCE/PG&E assert that NERC could take
advantage of ongoing state actions to
ensure reliable operation and to
coordinate with the states so there are
no conflicting obligations.396
217. NERC, AEP, Bonneville, CAISO,
and Ohio FEA generally support the
idea of a staggered standard
development plan but provide some
recommendations to adjust the schedule
to take advantage of NERC’s ongoing
standard development projects. NERC
proposes an alternate timeline whereby
it would submit proposed new or
modified Reliability Standards
addressing: (1) comprehensive ride
through requirements (including
391 Id.

at 23–24.
Trade Associations Initial
Comments at 2.
393 Id. at 5.
394 Id. at 6; IRC Initial Comments at 3.
395 SCE/PG&E Initial Comments at 9–11.
396 Id. at 10.
392 Indicated

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frequency, voltage, post-disturbance
ramp rates, and phase lock loop
synchronization), post-event
performance validation, and disturbance
monitoring data within 12 months of
Commission approval of the plan; (2)
data sharing issues, other than
disturbance monitoring data, and data
and model validation for registered and
unregistered IBRs and IBR–DERs in the
aggregate within 24 months of
Commission approval of the plan; and
(3) planning and operational studies for
registered and unregistered IBRs and
IBR–DERs in the aggregate within 36
months of Commission approval of the
plan.397 NERC explains that its alternate
timeline would leverage existing and
planned activities more efficiently and
address higher priority risks more
expeditiously, while allowing sufficient
time to develop consensus approaches
on other issues.398
218. AEP and CAISO support the
Commission’s proposed staggered
approach but suggest modifying the
proposal to include all aspects of ride
through performance (i.e., phase lock
loop synchronization and postdisturbance ramp rates) in the first
stage.399 Further, as NERC is working on
addressing currently unregistered IBR
generator owners and operators, AEP
recommends addressing the
interconnected issues related to
registered and unregistered IBR and
IBR–DER data sharing, validation, and
studies after the remaining directives in
the three-year time frame.400
219. Bonneville believes that the
three-year proposed timeline should be
extended to five years.401 Bonneville
explains that the proposed directives for
data sharing, model validation, and
studies will ‘‘require extensive industry
collaboration’’ and that a five-year
timeline will ensure that NERC and
industry have adequate time to develop
the standards, especially as Bonneville
notes there will be an increase in
generation interconnection requests and
corresponding need for additional
model validation.402
220. Ohio FEA anticipates that using
a staggered standards development
timeline will provide additional
opportunities for stakeholders to
participate in the development of the
new or modified Reliability Standards
and recommends robust comment
397 NERC

Initial Comments at 26–30.
at 24.
399 AEP Initial Comments at 5; CAISO Initial
Comments at 5.
400 AEP Initial Comments at 6.
401 Bonneville Initial Comments at 1.
402 Id. at 3.
398 Id.

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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations
periods at each stage in the staggered
approach.403
221. ACP/SEIA caution that, although
supportive of ride through
requirements, one year to develop such
standards is a short time when
compared with how long it typically
takes to develop Reliability Standards
and may be infeasible if NERC does not
use its existing standards development
projects to comply with the rule.404
2. Commission Determination
222. Pursuant to § 39.2(d) of the
Commission’s regulations,405 we modify
the NOPR proposal and direct NERC to
submit an informational filing within 90
days of the issuance of the final rule in
this proceeding. Further, pursuant to
section 215(d)(5)(g) of the FPA, we
direct NERC to submit new or modified
Reliability Standards addressing the
reliability concerns outlined herein by
certain deadlines, detailed further
below.
223. NERC’s informational filing
should include a detailed,
comprehensive standards development
plan and explanation of how NERC will
prioritize the development of new or
modified Reliability Standards directed
in this rule. We agree with NERC and
Indicated Trade Associations, among
others, that there are existing projects
that can be leveraged to address our
directives in a timely manner.406
Therefore, NERC should take into
account the risk posed to the reliability
of the Bulk-Power System, standard
development projects already
underway, resource constraints, its
ongoing registration of Bulk-Power
System-connected IBR generator owners
and operators, and other factors as
necessary.407 As we recognized in the
NOPR, data models and validation build
and rely upon the data sharing
directives. Similarly, the planning and
operational study directives require the
use of validated models and data
sharing.408
224. In its comments, NERC provides
an alternate timeline it explains would
leverage its existing and planned
activities more efficiently. It references
initiatives already underway and
highlights several ongoing standards
development projects that could be
403 Ohio

FEA Initial Comments at 7.
Initial Comments at 4.
405 18 CFR 39.2(d).
406 See, e.g., NERC Initial Comments at 22;
Indicated Trades Associations Initial Comments at
8 (discussing NERC Project 2020–02 Modifications
to PRC–024 (Generator Ride-through) and its
updated scope to address IBR ride through
performance).
407 See IBR Registration Order, 181 FERC
¶ 61,124.
408 NOPR, 181 FERC ¶ 61,125 at P 74.

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404 ACP/SEIA

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adjusted to address the directives in this
final action.409 As NERC explains in its
comments, a standards development
plan provides visibility to both the
Commission and stakeholders on how
NERC will address the important
reliability issues identified in this final
action. In the interest of time, however,
and as NERC appears to have already
extended considerable effort in thinking
through how it would address IBRrelated gaps through its Reliability
Standard projects, we do not find it
necessary to approve NERC’s final work
plan.
225. As requested by NERC, we clarify
that the Commission’s reference to
‘‘implementation’’ in the NOPR means
the date on which the new or modified
Reliability Standards would become
mandatory and enforceable for relevant
registered entities. But we find
persuasive NERC’s assertion that that
the implementation plan is better
developed standard-by-standard
through NERC’s Commission approved
Reliability Standard development
process. Therefore, we decline to direct
NERC to include in its informational
filing the dates by which all of the new
or modified Reliability Standards would
be mandatory and effective.
226. Although we are not directing
NERC to include implementation dates
in its informational filing and are
leaving determination of the proposed
effective dates to the standards
development process, we are concerned
that the lack of a time limit for
implementation could allow identified
issues to remain unresolved for a
significant and indefinite period.
Therefore, we emphasize that industry
has been aware of and alerted to the
need to address the impacts of IBRs on
the Bulk-Power System since at least
2016. The number of events, NERC
Alerts, reports, whitepapers, guidelines,
and ongoing standards projects more
than demonstrate the need for the
expeditious implementation of new or
modified Reliability Standards
addressing IBR data sharing, data and
model validation, planning and
operational studies, and performance
requirements. Thus, in that light, the
Commission will consider the justness
and reasonableness of each new or
modified Reliability Standard’s
implementation plan when it is
submitted for Commission approval.410
409 NERC

Initial Comments at 21–22.
Order No. 672, 114 FERC ¶ 61,104 at P 333
(‘‘In considering whether a proposed Reliability
Standard is just and reasonable, the Commission
will consider also the timetable for implementation
of the new requirements, including how the
proposal balances any urgency in the need to
410 See

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74285

Further, we believe that there is a need
to have all of the directed Reliability
Standards effective and enforceable well
in advance of 2030 and direct NERC to
ensure that the associated
implementation plans sequentially
stagger the effective and enforceable
dates to ensure an orderly industry
transition for complying with the IBR
directives in this final action prior to
that date.
227. We decline to direct NERC to
implement a pilot program to better
analyze the impact of IBRs on the BulkPower System as requested by SCE/
PG&E. While there may be merit in
conducting a pilot program for systems
with high-IBR penetrations to better
understand what information is
available to distribution providers,
generator owners, generator operators,
transmission owners, and transmission
operators within these footprints, we
leave to NERC’s discretion the value of
such a study; and in any case such a
pilot program must not impact the
prioritization or timely completion of
the directed Reliability Standards.
228. We agree with NERC, CAISO,
and AEP that the stages should be
modified from the NOPR proposal to
group the ride through directives and
the development of new or modified
Reliability Standards for data sharing
and model validation to inform the
standard development for planning and
operational studies.
229. Therefore, as we are persuaded
by commenters’ suggestions regarding
the proposed staggered groupings for
new or modified Reliability Standards,
we modify the NOPR proposal to adopt
NERC’s proposed staggered grouping
that would result in NERC submitting
new or modified Reliability Standards
in three stages. NERC’s standards
development plan submitted as a part of
its informational filing must ensure that
NERC submits new or modified
Reliability Standards by the following
deadlines. First, by November 4, 2024,
NERC must submit new or modified
Reliability Standards that establish IBR
performance requirements, including
requirements addressing frequency and
voltage ride through, post-disturbance
ramp rates, phase lock loop
synchronization, and other known
causes of IBR tripping or momentary
cessation (section IV.E.). NERC must
also submit, by November 4, 2024, new
or modified Reliability Standards that
require disturbance monitoring data
sharing and post-event performance
validation for registered IBRs (section
IV.B.2.). Second, by November 4, 2025,
implement it against the reasonableness of the time
allowed for those who must comply.’’).

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NERC must submit new or modified
Reliability Standards addressing the
interrelated directives concerning: (1)
data sharing for registered IBRs (section
IV.B.1), unregistered IBRs (section
IV.B.3.), and IBR–DERs in the aggregate
(section IV.B.3.); and (2) data and model
validation for registered IBRs,
unregistered IBRs, and IBR–DERs in the
aggregate (section IV.C.). Finally, by
November 4, 2026, NERC must submit
new or modified Reliability Standards
addressing planning and operational
studies for registered IBRs, unregistered
IBRs, and IBR–DERs in the aggregate
(section IV.D.). We continue to believe
this staggered approach to standard
development is necessary based on the
scope of work anticipated and that
specific target dates will provide a
valuable tool and incentive to NERC to
timely address the directives in this
final action.
230. NERC may expedite its standards
development plan and submit new or
modified Reliability Standards prior to
the deadlines. We decline to extend the
three-year staggered approach to a fiveyear staggered approach as requested by
Bonneville due to the pressing nature of
the Commission’s concerns discussed
above, such as IBR momentary cessation
occurring in the aggregate today that can
lead to instability, system-wide
uncontrolled separation, and voltage
collapse.

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V. Information Collection Statement
231. The information collection
requirements contained in this order are
subject to review by the Office of
Management and Budget (OMB) under
section 3507(d) of the Paperwork
Reduction Act of 1995.411 OMB’s
regulations require approval of certain
information collection requirements
imposed by agency rules.412 Upon
approval of a collection of information,
OMB will assign an OMB control
number and expiration date.
Respondents subject to the filing
requirements of this rule will not be
penalized for failing to respond to this
collection of information unless the
collection of information displays a
valid OMB control number. Comments
are solicited on the Commission’s need
for the information proposed to be
reported, whether the information will
have practical utility, ways to enhance
the quality, utility, and clarity of the
information to be collected, and any
suggested methods for minimizing the
respondent’s burden, including the use
of automated information techniques.
411 44
412 5

U.S.C. 3507(d).
CFR 1320.11.

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232. The directives to NERC to submit
new or modified Reliability Standards
that address specific matters pertaining
to the impacts of IBRs on the reliable
operation of the Bulk-Power System are
covered by, and already included in, the
existing OMB-approved information
collection FERC–725 (Certification of
Electric Reliability Organization;
Procedures for Electric Reliability
Standards; OMB Control No. 1902–
0225), under Reliability Standards
Development.413 In this final action, we
direct NERC to develop new or modify
the currently effective Reliability
Standards to address these issues and,
when these Reliability Standards are
submitted to the Commission for
approval, to explain in the
accompanying petition how the issues
are addressed in the proposed new or
modified Reliability Standards. NERC
may propose to develop new or
modified Reliability Standards that
address our concerns in an equally
efficient and effective manner; however,
NERC’s proposal should explain how
the new or modified Reliability
Standards address the Commission’s
concerns discussed in this final action.
233. Necessity of Information. Direct
NERC to develop new or modified
Reliability Standards addressing
reliability gaps pertaining to IBRs in
four areas: (1) data sharing; (2) model
validation; (3) planning and operational
studies; and (4) performance
requirements.
VI. Environmental Analysis
234. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.414 The Commission has
categorically excluded certain actions
from this requirement as not having a
significant effect on the human
environment. Included in the exclusion
are rules that are clarifying, corrective,
or procedural or that do not
substantially change the effect of the
413 Reliability Standards Development as
described in FERC–725 covers standards
development initiated by NERC, the Regional
Entities, and industry, as well as Reliability
Standards the Commission may direct NERC to
develop or modify. The information collection
associated with this final action ordinarily would
be a non-material addition to FERC–725. However,
an information collection request unrelated to this
final action is pending review under FERC–725 at
the Office of Management and Budget. To submit
this final action timely to OMB, we will submit this
to OMB as a temporary placeholder under FERC–
725(1A), OMB Control No. 1902–0289.
414 Reguls. Implementing the Nat’l Env’t Pol’y
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987),
FERC Stats. & Regs. ¶ 30,783 (1987) (crossreferenced at 41 FERC ¶ 61,284).

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regulations being amended.415 The
actions directed herein fall within this
categorical exclusion in the
Commission’s regulations.
VII. Regulatory Flexibility Act
235. The Regulatory Flexibility Act of
1980 (RFA) 416 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. This final action directs NERC,
the Commission-certified ERO, to
develop new or modified Reliability
Standards for IBRs on the Bulk-Power
System. Therefore, this final action will
not have a significant or substantial
impact on entities other than NERC.417
Consequently, the Commission certifies
that this final action will not have a
significant economic impact on a
substantial number of small entities.
236. Any new or modified Reliability
Standards proposed by NERC in
compliance with this rulemaking will be
considered by the Commission in future
proceedings. As part of any future
proceedings, the Commission will make
determinations pertaining to the RFA
based on the content of the Reliability
Standards proposed by NERC.
VIII. Document Availability
237. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the internet through the
Commission’s Home Page (http://
www.ferc.gov).
238. From FERC’s Home Page on the
internet, this information is available on
eLibrary. The full text of this document
is available on eLibrary in PDF and
Microsoft Word format for viewing,
printing, and/or downloading. To access
this document in eLibrary, type the
docket number excluding the last three
digits of this document in the docket
number field.
239. User assistance is available for
eLibrary and the FERC’s website during
normal business hours from FERC
Online Support at (202) 502–6652 (toll
free at 1–866–208–3676) or email at
[email protected], or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. Email the
Public Reference Room at
[email protected].
415 18

CFR 380.4(a)(2)(ii).
U.S.C. 601–612.
417 See, e.g., Transmission Sys. Plan. Performance
Requirements for Extreme Weather, Order No. 896,
88 FR 41262 (June 23, 2023), 183 FERC ¶ 61,191,
at P 198 (2023).
416 5

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IX. Effective Date and Congressional
Notification
240. This final action is effective
December 29, 2023. The Commission
has determined, with the concurrence of
the Administrator of the Office of
Information and Regulatory Affairs of

OMB, that this rule is not a ‘‘major rule’’
as defined in section 351 of the Small
Business Regulatory Enforcement
Fairness Act of 1996.
By the Commission. Commissioner
Danly is concurring with a separate
statement attached.

Acronyms

infiniRel ...........................................
ISO–NE ...........................................
IRC ..................................................
NYSRC ............................................
LADWP ...........................................
Ohio FEA ........................................
Mr. Plankey .....................................
SCE/PG&E ......................................
SPP .................................................
UNIFI ...............................................

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Appendix A: Commenter Names

Advanced Energy United.
American Clean Power Association and Solar Energy Industries Association.
American Electric Power Service Corporation.
Arizona Public Service Company.
Bonneville Power Administration.
California Independent System Operator Corporation.
Electric Power Research Institute.
Edison Electric Institute, American Public Power Association, Large Public Power Council, National Rural
Electric Cooperative Association, and Transmission Access Policy Study Group.
infiniRel Corporation.
ISO New England Inc.
ISO/RTO Council.
New York State Reliability Council.
Los Angeles Department of Water and Power.
Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate.
Sean P. Plankey.
Southern California Edison Company and Pacific Gas and Electric Company.
Southwest Power Pool, Inc.
Universal Interoperability for Grid-forming Inverters Consortium.

Appendix B: NERC IBR Resources Cited
in the Final Action
NERC Guidelines
NERC Guidelines referenced in this NOPR
are available here: https://www.nerc.com/
comm/Pages/Reliability-and-SecurityGuidelines.aspx.
NERC, Reliability Guideline: Modeling
Distributed Energy Resources in Dynamic
Load Models (Dec. 2016), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline_-_
Modeling_DER_in_Dynamic_Load_Models_-_
FINAL.pdf (retired).
NERC, Reliability Guideline: Distributed
Energy Resources Modeling, (Sept. 2017),
https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline_
-_DER_Modeling_Parameters_-_2017-08-18__FINAL.pdf (retired).
NERC, Reliability Guideline: BPSConnected Inverter-Based Resource
Performance (Sept. 2018), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Inverter-Based_Resource_
Performance_Guideline.pdf (IBR Performance
Guideline).
NERC, Reliability Guideline:
Parameterization of the DER_A Model (Sept.
2019), https://www.nerc.com/comm/RSTC_
Reliability_Guidelines/Reliability_Guideline_
DER_A_Parameterization.pdf (2019 DER_A
Model Guideline) (retired).
NERC, Reliability Guideline: DER Data
Collection for Modeling in Transmission
Planning Studies (Sept. 2020), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline_DER_Data_
Collection_for_Modeling.pdf (IBR–DER Data
Collection Guideline).
NERC, Reliability Guideline: Model
Verification of Aggregate DER Models used in

17:37 Oct 27, 2023

Issued October 19, 2023
Kimberly D. Bose,
Secretary.

Commenter name

AEU .................................................
ACP/SEIA ........................................
AEP .................................................
APS .................................................
Bonneville ........................................
CAISO .............................................
EPRI ................................................
Indicated Trade Associations ..........

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Planning Studies (Mar. 2021), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline%20_DER_
Model_Verification_of_Aggregate_DER_
Models_used_in_Planning_Studies.pdf
(Aggregate DER Model Verification
Guideline).
NERC, Reliability Guideline:
Parameterization of the DER_A Model for
Aggregate DER (Feb. 2023), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline_
ModelingMerge_Responses_clean.pdf (2023
DER_A Model Guideline).
NERC, Reliability Guideline:
Electromagnetic Transient Modeling for BPSConnected Inverter-Based Resources—
Recommended Model Requirements and
Verification Practices (Mar. 2023), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/Reliability_Guideline-EMT_
Modeling_and_Simulations.pdf.
NERC White Papers
IRPTF white papers referenced in this
NOPR are available here: https://nerc.com/
comm/PC/Pages/Inverter-Based-ResourcePerformance-Task-Force.aspx.
NERC, A Concept Paper on Essential
Reliability Services that Characterizes Bulk
Power System Reliability (Oct. 2014), https://
www.nerc.com/comm/Other/essntlrlbltys
rvcstskfrcDL/ERSTF%20
Concept%20Paper.pdf (Essential Reliability
Services Concept Paper).
NERC, Resource Loss Protection Criteria
Assessment (Feb. 2018), https://
www.nerc.com/comm/PC/InverterBased
%20Resource%20Performance%20
Task%20Force%20IRPT/IRPTF_RLPC_
Assessment.pdf.
NERC, Fast Frequency Response Concepts
and Bulk Power System Reliability Needs
(Mar. 2020), https://www.nerc.com/comm/

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PC/InverterBased%20
Resource%20Performance%20
Task%20Force%20IRPT/Fast_Frequency_
Response_Concepts_and_BPS_Reliability_
Needs_White_Paper.pdf (Fast Frequency
Response White Paper).
NERC Reports
NERC, 2013 Long-Term Reliability
Assessment (Dec. 2013), https://
www.nerc.com/pa/RAPA/ra/Reliability%20
Assessments%20DL/2013_LTRA_FINAL.pdf
(2013 LTRA Report).
NERC, Distributed Energy Resources:
Connection Modeling and Reliability
Considerations (Feb. 2017), https://
www.nerc.com/comm/Other/essntlrlblty
srvcstskfrcDL/Distributed_Energy_Resources_
Report.pdf (NERC DER Report).
NERC, 2020 Long Term Reliability
Assessment Report (Dec. 2020), https://
www.nerc.com/pa/RAPA/ra/Reliability%
20Assessments%20DL/NERC_LTRA_
2020.pdf (2020 LTRA Report).
NERC, 2021 Long Term Reliability
Assessment Report (Dec. 2021), https://
www.nerc.com/pa/RAPA/ra/Reliability%20
Assessments%20DL/NERC_LTRA_2021.pdf
(2021 LTRA Report).
NERC Technical Reports
NERC technical reports referenced in this
NOPR are available here: https://nerc.com/
comm/PC/Pages/Inverter-Based-ResourcePerformance-Task-Force.aspx.
NERC, Technical Report, BPS-Connected
Inverter-Based Resource Modeling and
Studies (May 2020), https://www.nerc.com/
comm/PC/InverterBased%20
Resource%20Performance%20
Task%20Force%20IRPT/IRPTF_IBR_
Modeling_and_Studies_Report.pdf (Modeling
and Studies Report).

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NERC and WECC, WECC Base Case
Review: Inverter-Based Resources (Aug.
2020), https://www.nerc.com/comm/PC/
InverterBased%20
Resource%20Performance%20
Task%20Force%20IRPT/NERC-WECC_2020_
IBR_Modeling_Report.pdf (Western
Interconnection Base Case IBR Review).
NERC Major Event Reports
NERC event reports referenced in this
NOPR are available here: https://
www.nerc.com/pa/rrm/ea/Pages/MajorEvent-Reports.aspx.
NERC, 1,200 MW Fault Induced Solar
Photovoltaic Resource Interruption
Disturbance Report (June 2017), https://
www.nerc.com/pa/rrm/ea/1200_MW_Fault_
Induced_Solar_Photovoltaic_Resource_/
1200_MW_Fault_Induced_Solar_
Photovoltaic_Resource_Interruption_
Final.pdf (Blue Cut Fire Event Report)
(covering the Blue Cut Fire event (August 16,
2016)).
NERC and WECC, 900 MW Fault Induced
Solar Photovoltaic Resource Interruption
Disturbance Report (Feb. 2018), https://
www.nerc.com/pa/rrm/ea/October%209%
202017%20Canyon%202%
20Fire%20Disturbance%20Report/900%
20MW%20Solar%20Photovoltaic%
20Resource%20Interruption%20
Disturbance%20Report.pdf (Canyon 2 Fire
Event Report) (covering the Canyon 2 Fire
event (October 9, 2017)).
NERC and WECC, April and May 2018
Fault Induced Solar Photovoltaic Resource
Interruption Disturbances Report (Jan. 2019),
https://www.nerc.com/pa/rrm/ea/April_May_
2018_Fault_Induced_Solar_PV_Resource_
Int/April_May_2018_Solar_PV_Disturbance_
Report.pdf (Angeles Forest and Palmdale
Roost Events Report) (covering the Angeles
Forest (April 20, 2018) and Palmdale Roost
(May 11, 2018) events).
NERC and WECC, San Fernando
Disturbance, (Nov. 2020), https://
www.nerc.com/pa/rrm/ea/Documents/San_
Fernando_Disturbance_Report.pdf (San
Fernando Disturbance Report) (covering the
San Fernando event (July 7, 2020)).
NERC and Texas RE, Odessa Disturbance
(Sept. 2021) https://www.nerc.com/pa/rrm/
ea/Documents/Odessa_Disturbance_
Report.pdf (Odessa 2021 Disturbance Report)
(covering events in Odessa, Texas on May 9,
2021 and June 26, 2021).
NERC and WECC, Multiple Solar PV
Disturbances in CAISO (Apr. 2022), https://
www.nerc.com/pa/rrm/ea/Documents/NERC_
2021_California_Solar_PV_Disturbances_
Report.pdf (2021 Solar PV Disturbances
Report) (covering four events: Victorville
(June 24, 2021); Tumbleweed (July 4, 2021);
Windhub (July 28, 2021); and Lytle Creek
(August 26, 2021)).
NERC and Texas RE, March 2022
Panhandle Wind Disturbance Report (Aug.
2022), https://www.nerc.com/pa/rrm/ea/
Documents/Panhandle_Wind_Disturbance_
Report.pdf (Panhandle Disturbance Report)
(covering the Texas Panhandle event (March
22, 2022)).
NERC and Texas RE, 2022 Odessa
Disturbance (Dec. 2022), https://
www.nerc.com/comm/RSTC_Reliability_

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Guidelines/NERC_2022_Odessa_
Disturbance_Report%20(1).pdf (Odessa 2022
Disturbance Report) (covering events in
Odessa, Texas on June 4, 2022).
NERC and WECC, 2023 Southwest Utah
Disturbance (Aug. 2023), https://
www.nerc.com/comm/RSTC_Reliability_
Guidelines/NERC_2023_Southwest_UT_
Disturbance_Report.pdf (Southwest Utah
Disturbance Report) (covering events in
Southwestern Utah on April 10, 2023).
NERC Alerts
NERC Alerts referenced in this NOPR are
available here: https://www.nerc.com/pa/
rrm/bpsa/Pages/Alerts.aspx.
NERC, Industry Recommendation: Loss of
Solar Resources during Transmission
Disturbances due to Inverter Settings—II
(May 2018), https://www.nerc.com/pa/rrm/
bpsa/Alerts%20DL/NERC_Alert_Loss_of_
Solar_Resources_during_Transmission_
Disturbance-II_2018.pdf (Loss of Solar
Resources Alert II).
NERC, Industry Recommendation: InverterBased Resource Performance Issues, (Mar.
2023), https://www.nerc.com/pa/rrm/bpsa/
Alerts%20DL/NERC%20Alert%20R-2023-0314-01%20Level%202%20-%20InverterBased%20Resource%20Performance
%20Issues.pdf (March 2023 Alert).
Other NERC Resources
NERC Libraries of Standardized Powerflow
Parameters and Standardized Dynamics
Models version 1 (Oct. 2015), https://
www.nerc.com/comm/PC/Model%20
Validation%20Working%20Group
%20MVWG%202013/NERC%20
Standardized%20Component%20
Model%20Manual.pdf (NERC Standardized
Powerflow Parameters and Dynamics
Models).
NERC, Events Analysis Modeling
Notification Recommended Practices for
Modeling Momentary Cessation Initial
Distribution (Feb. 2018), https://
www.nerc.com/comm/PC/
NERCModelingNotifications/Modeling_
Notification_-_Modeling_Momentary_
Cessation_-_2018-02-27.pdf.
NERC, Case Quality Metrics Annual
Interconnection-wide Model Assessment,
(Oct. 2021), https://www.nerc.com/pa/RAPA/
ModelAssessment/ModAssessments/2021_
Case_Quality_Metrics_AssessmentFINAL.pdf.
NERC, Inverter-Based Resource Strategy:
Ensuring Reliability of the Bulk Power
System with Increased Levels of BPSConnected IBRs (Sept. 2022), https://
www.nerc.com/comm/Documents/NERC_
IBR_Strategy.pdf (NERC IBR Strategy).

United States of America
Federal Energy Regulatory Commission
Reliability Standards to Address
Inverter-Based Resources
Docket No. RM22–12–000
DANLY, Commissioner, concurring:
1. I concur in today’s order 1 in which
we direct NERC to develop new or
1 Reliability Standards to Address Inverter-Based
Resources, 185 FERC ¶ 61,042 (2023).

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modified mandatory and enforceable
Reliability Standards prior to 2030 in
order to address a set of reliability risks
we have known about, and been actively
discussing, since at least 2016 and about
which I have long warned. Is today’s
order important and necessary? Yes. Is
it timely? No. Six of the thirteen
documented events occurred in 2021.2
The Commission and NERC could have,
and should have, acted sooner,
particularly since 2030 marks the time
at which inverter-based resources (IBRs)
‘‘are projected to account for a
significant share of the electric energy
generated in the United States.’’ 3
2. The reliability risks at issue arise
from the rapid, widespread (one might
say reckless) addition of IBRs (e.g., wind
and solar) to the Bulk-Power System
(BPS).4 According to NERC, ‘‘[t]he rapid
interconnection of [BPS]-connected
[IBRs] is the most significant driver of
grid transformation and poses a high
risk to BPS reliability.’’ 5 As NERC has
explained, ‘‘[e]ach event analyzed has
identified new performance issues, such
as momentary cessation, unwarranted
inverter or plant-level tripping issues,
controller interactions and instabilities,
and other critical performance risks that
must be mitigated.’’ 6 ‘‘Simulations
conducted by the NERC Resource
Subcommittee demonstrate that the
risks to the [BPS] reliability posted by
momentary cessation are greater than
any of the actual IBR disturbances that
NERC has documented since 2016 . . .
These simulation results indicate that
IBR momentary cessation occurring in
the aggregate can lead to instability,
system-wide uncontrolled separation,
and voltage collapse.’’ 7
3. NERC has also observed ‘‘[m]ultiple
recent disturbances that involve the
2 Id. P 26 & n.53 (‘‘The 12 events report an average
of approximately 1,000 MW of IBRs entering into
momentary cessation or tripping in the aggregate.
The 12 Bulk-Power System events are: (1) the Blue
Cut Fire (August 16, 2016); (2) the Canyon 2 Fire
(October 9, 2017); (3) Angeles Forest (April 20,
2018); (4) Palmdale Roost (May 11, 2018); (5) San
Fernando (July 7, 2020); (6) the first Odessa, Texas
event (May 9, 2021); (7) the second Odessa, Texas
event (June 26, 2021); (8) Victorville (June 24,
2021); (9) Tumbleweed (July 4, 2021); (10) Windhub
(July 28, 2021); (11) Lytle Creek (August 26, 2021);
and (12) Panhandle Wind Disturbance (March 22,
2022).’’). On June 4, 2022, an IBR-related
disturbance near Odessa, Texas (the third in this
location) occurred. Id. P 27.
3 Id. P 58 (footnote omitted).
4 Id. P 2.
5 NERC, Inverter-Based Resource Strategy:
Ensuring Reliability of the Bulk Power System with
Increased Levels of BPS-Connected IBRs, at 1 (June
2022) (footnote omitted), https://www.nerc.com/
comm/Documents/NERC_IBR_Strategy.pdf.
6 Id. at 4.
7 Reliability Standards to Address Inverter-Based
Resources, 185 FERC ¶ 61,042 at P 14 (citations
omitted).

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widespread reduction of solar
photovoltaic (PV) resources have
occurred in California, Utah, and
Texas.’’ 8 The ‘‘first major events
involving [battery energy storage system
facilities’’ occurred just last year in
March and April, 2022.9 The reliable

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8 2022 California Battery Energy Storage Sys.
Disturbances, California Events: March 9 and April
6, 2022, Joint NERC and WECC Staff Report, at iv
(Sept. 2023), https://www.nerc.com/comm/RSTC/
Documents/NERC_BESS_Disturbance_Report_
2023.pdf.
9 Id.

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operation of the Bulk-Power System
remains imperiled until these issues are
addressed. Time is of the essence.
4. Our oversight role requires us to
remain vigilant in ensuring that NERC
Reliability Standards are timely,
efficient, and effective. Up to nearly
fourteen years to establish mandatory
and enforceable NERC Reliability
Standards to address a known, and
potentially catastrophic, risk to the
reliability of the BPS is simply too long
a time to wait. And we will have to wait

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yet longer to learn whether the
standards we do ultimately implement
end up proving effective. Who knows
what will happen in the meantime.
5. Better late than never, I suppose.
For these reasons, I respectfully
concur.
lllllllllllllllllll
James P. Danly,
Commissioner.
[FR Doc. 2023–23581 Filed 10–27–23; 8:45 am]
BILLING CODE 6717–01–P

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