74250 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

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 

AGENCY: Federal Energy Regulatory 

Commission, Department of Energy. 

ACTION: Final action. 

SUMMARY: The Federal Energy 

Regulatory Commission (Commission) is 

directing the North American Electric 

Reliability Corporation (NERC), the 

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, Eugene.Blick@ferc.gov. 

Felicia West (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street NE, Washington, DC 20426, 

(202) 502–8948, Felicia.West@ferc.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

Nos. 

I. Information .......................................................................................................................................................................................... 1 

II. Background ......................................................................................................................................................................................... 9 

A. Section 215 of the FPA and the Mandatory Reliability Standards ......................................................................................... 9 

B. Inverter-Based Resources ........................................................................................................................................................... 11 

C. Notice of Proposed Rulemaking ................................................................................................................................................ 16 

III. Need for Reform ................................................................................................................................................................................ 24 

A. Current Actions Are Insufficient To Address IBR Reliability Risks ....................................................................................... 26 

B. Existing Reliability Standards Do Not Adequately Address IBR Reliability Risks ................................................................ 37 

1. Data Sharing ......................................................................................................................................................................... 37 

2. Data and Model Validation ................................................................................................................................................. 42 

3. Planning and Operational Studies ...................................................................................................................................... 49 

4. Performance Requirements .................................................................................................................................................. 50 

IV. Discussion ......................................................................................................................................................................................... 53 

A. Commission Authority To Direct the ERO To Develop New or Modified Reliability Standards Under Section 215 of 

the FPA ......................................................................................................................................................................................... 59 

1. Comments ............................................................................................................................................................................. 60 

2. Commission Determination ................................................................................................................................................. 63 

B. Data Sharing ................................................................................................................................................................................ 66 

1. Registered IBR Data Sharing ............................................................................................................................................... 68 

2. Disturbance Monitoring Data Sharing ................................................................................................................................ 81 

3. Unregistered IBR and IBR–DER Data Sharing .................................................................................................................... 87 

C. Data and Model Validation ........................................................................................................................................................ 110 

1. Approved Component Models ............................................................................................................................................ 112 

2. Verification of IBR Plant Dynamic Model Performance .................................................................................................... 128 

3. Validating and Updating System Models ........................................................................................................................... 151 

4. Need for Coordination When Creating and Updating Planning, Operational, and Interconnection-Wide Data and 

Models ................................................................................................................................................................................... 158 

D. Planning and Operational Studies ............................................................................................................................................. 162 

1. Comments ............................................................................................................................................................................. 167 

2. Commission Determination ................................................................................................................................................. 174 

E. Performance Requirements ......................................................................................................................................................... 178 

1. Registered IBR Frequency and Voltage Ride Through Requirements .............................................................................. 178 

2. Bulk-Power System Planners and Operators Voltage Ride Through Mitigation Activities ............................................ 196 

3. Post-Disturbance IBR Ramp Rate Interactions and Phase Lock Loop Synchronization .................................................. 200 

F. Informational Filing and Reliability Standard Development Timeline ................................................................................... 212 

1. Comments ............................................................................................................................................................................. 214 

2. Commission Determination ................................................................................................................................................. 222 

V. Information Collection Statement ..................................................................................................................................................... 231 

VI. Environmental Analysis ................................................................................................................................................................... 234 

VII. Regulatory Flexibility Act ............................................................................................................................................................... 235 

VIII. Document Availability ................................................................................................................................................................... 237 

IX. Effective Date and Congressional Notification ............................................................................................................................... 240 

Appendix A: Commenter Names.

Appendix B: NERC IBR Resources Cited in the Final Action.


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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 74251 

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). 

2The 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. 

3This 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. 

4The 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. 

5The 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. 

6Reliability 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). 

7See, 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.’’). 

8The 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.’’ 

9NERC, 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). 

10An 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. 

11NERC, 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). 

12See, 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.’’). 

13Bulk-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. 

14NERC 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). 

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 

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 


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74252 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

15See, 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). 

16 18 CFR 39.2(d) (the electric reliability 

organization shall provide the Commission 

information as necessary to implement section 215 

of the FPA). 17See 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.’’). 

18Momentary 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). 

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 

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 

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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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 74253 

19 16 U.S.C. 824o(c). 

20 Id. 824o(e). 

21Rules 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). 

22N. 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). 

25See, 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. 

26NERC 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)). 

27See 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). 

28The 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. 

29NERC, 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’’). 

30See NOPR, 181 FERC ¶ 61,125 at P 4. 

31See, 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). 

32The 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’’). 

33See, 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 

Continued 

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 

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 

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 


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facilities poses risks to [Bulk-Power System] 

performance and reliability.’’). 

34See 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. 

36See, 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.’’). 

37See, e.g., Fast Frequency Response White Paper 

at 11. 

38NOPR, 181 FERC ¶ 61,125 at P 1. 

39 Id. P 2 (citing 2020 LTRA Report). 

40 Id. 

41 Id. P 6. 

42NERC 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. 

43NOPR, 181 FERC ¶ 61,125 at P 5. 

44 Id. 

45 Id. 

46 Id. 

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 

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 

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 


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47 Id. (citing Essential Reliability Services 

Concept Paper at vi). 

48 Id. P 7. 

49A 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. 

50See NOPR, 181 FERC ¶ 61,125 at PP 24–26. 

51 Id. PP 26–27. 

52For 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. 

53The 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). 

54NOPR, 181 FERC ¶ 61,125 at P 4. 

55A 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.’’). 

56See Reliability Standard BAL–003–2 

(Frequency Response and Frequency Bias Setting), 

attach. A. 

57NERC 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 

Continued 

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 

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 

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


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Disturbance Report) (covering events in Odessa, 

Texas on June 4, 2022). 

58NERC, Industry Recommendation: InverterBased Resource Performance Issues (Mar. 2023), 

https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/ 

NERC%20Alert%20R-2023-03-14- 

01%20Level%202%20-%20InverterBased%20Resource%20Performance%20Issues.pdf 

(March 2023 Alert). 

59See NOPR, 181 FERC ¶ 61,125 at P 18 

(explaining that the level 2 alerts recommend 

specific voluntary action to be taken by registered 

IBRs). 

60March 2023 Alert at 1. 

61 Id. 

62NERC 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. 

65Multiple 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. 

66San 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. 

67NERC, 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/. 

68NERC, 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). 

69The 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 

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. 

70March 2023 Alert at 6–7. 

71 Id. at 6. 

72See IBR Registration Order, 181 FERC ¶ 61,124 

at P 6. 

73N. 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). 

74See Improvements to Generator 

Interconnection Agreements & Procs., Order No. 

2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC 

¶ 61,054 (2023). 

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 

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

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 


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75 Id. PP 1661, 1715. 

76 IEEE, 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. 

78UL 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. 

79The 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/; 

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.’’). 

80NOPR, 181 FERC ¶ 61,125 at P 27. 

81NERC 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). 

82NOPR, 181 FERC ¶ 61,125 at P 28. 

83See 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). 

84See 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). 

85NERC 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’’). 

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

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 

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 


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86NERC, 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. 

87NOPR, 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). 

88See 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; 

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)). 

89See 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.’’). 

90See, 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.). 

91See Reliability Standard MOD–033–2 (SteadyState and Dynamic System Model Validation). 

92This final action uses the term ‘‘system 

models’’ to refer collectively to planning and 

operations transmission area models and 

interconnection-wide models. 

93See 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). 

94NERC, 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.). 

95See 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). 

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

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 

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 


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96Some 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. 

97NERC 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). 

98See, 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.’’). 

99NERC 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 

systems). 

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). 

101See Reliability Standard MOD–026–1. 

102See Reliability Standard MOD–027–1. 

103Reliability Standard MOD–033–2, 

Requirements R1, R2. 

104NERC 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. 

105This 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. 

106See NOPR, 181 FERC ¶ 61,125 at P 39 n.91. 

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 

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 

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 


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107Reliability 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. 

108Reliability 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 

Standard TPL–001–5, Order No. 867, 170 FERC 

¶ 61,030 (2020) (approving Reliability Standard 

TPL–001–5). 

109See 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.’’). 

110Odessa 2022 Disturbance Report at vii–ix. 

111Reliability 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. 

112The 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. 

113See NOPR, 181 FERC ¶ 61,125 at P 4. 

114NERC Initial Comments at 2. 

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. 

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

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

4. Performance Requirements 

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 

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 


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115See, e.g., Order No. 693, 118 FERC ¶ 61,218 at 

PP 186, 297. 

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. 

117See 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.’’). 

118See supra P 7. 

119See, 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. 

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. 

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 

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 


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120NOPR, 181 FERC ¶ 61,125 at P 68. 

121NERC Initial Comments at 7. 

122See, e.g., id.; AEP Initial Comments at 2; 

Bonneville Initial Comments at 1; CAISO Initial 

Comments at 1; NYSRC Initial Comments at 1. 

123See, 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. 

125ACP/SEIA Initial Comments at 4. 

126EPRI Initial Comments at 4. 

127 Indicated Trade Association Comments at 1. 

128Ohio FEA Initial Comments at 4. 

129 Id. at 5. 

130Ohio 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). 

132See supra P 32. 

133 16 U.S.C. 824o(a)(3). 

134 Id. 824o(a)(4). 

135 Id. 824o(a)(1). 

136Ohio 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. 

137See 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). 

138See Id. P 15 (explaining that NERC’s 

communication plan outlines how NERC will 

coordinate with key stakeholders). 

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

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 

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


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139NOPR, 181 FERC ¶ 61,125 at P 76. 

140Reliability Standard TOP–003–5 and 

Reliability Standard IRO–010–4 became effective 

April 1, 2023. 

141NOPR, 181 FERC ¶ 61,125 at P 76. 

142 Id. P 77. 

143 Id. P 78. 

144 Id. 

145See, e.g., NERC Initial Comments at 8; CAISO 

Initial Comments at 24. 

146NERC 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). 

149CAISO Initial Comments at 7. 

150 Id. at 30–31. 

151SPP Initial Comments at 2. 

152ACP/SEIA Initial Comments at 11–12. 

153AEU Initial Comments at 4; ACP/SEIA Initial 

Comments at 12–13. 

154AEU Initial Comments at 4. 

155 Id. at 5. 

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 

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 

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 


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156ACP/SEIA Initial Comments at 12; Mr. 

Plankey Initial Comments at 1; Ohio FEA Initial 

Comments at 9. 

157Ohio FEA Initial Comments at 9. 

158See 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). 159NOPR, 181 FERC ¶ 61,125 at P 78. 

160See 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. 

161NERC Initial Comments at 9; Indicated Trade 

Associations Initial Comments at 6. 

162See 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. 

164CAISO Initial Comments at 40. 

165ACP/SEIA Comments at 12. 

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 

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 

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 

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 


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166See 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). 

167See supra note 88. 

168See 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’’). 

169NOPR, 181 FERC ¶ 61,125 at P 79. 

170 Id. 

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 

Continued 

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 

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 

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


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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). 

175See 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. 

176See 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. 

177NERC Initial Comments at 9; AEU Initial 

Comments at 4, 7; IRC Initial Comments at 2; ISO– 

NE Initial Comments at 2. 

178NERC Initial Comments at 13. 

179 Id. 

180 IRC Initial Comments at 2. 

181 Id. at 3. 

182 ISO–NE Reply Comments at 2, 5. 

183 ISO–NE Initial Comments at 2. 

184Ohio FEA Initial Comments at 2, 9. 

185AEU Initial Comments at 7. 

186CAISO Initial Comments at 31; Indicated 

Trade Associations Initial Comments at 9; SPP 

Initial Comments at 2. 

187CAISO Initial Comments at 32, 38. 

188APS Initial Comments at 4; AEP Initial 

Comments at 2; LADWP Reply Comments at 2; SCE/ 

PG&E Initial Comments at 6. 

189AEP Initial Comments at 4. 

190SCE/PG&E Initial Comments at 6–7. 

191APS Initial Comments at 4. 

192 Id. at 4. 

193 Indicated Trade Associations Initial 

Comments at 10. 

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 

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 

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


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194APS Initial Comments at 4. 

195 Indicated Trade Associations Initial 

Comments at 10–13. 

196 Id. at 9, 12–13. 

197 Id. at 2. 

198See 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). 

199See, 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. 

200See, e.g., AEP Initial Comments at 2; SCE/ 

PG&E Initial Comments at 6–7. 

201For 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. 

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

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 

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 


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202See supra note 89. 

203See infra P 147 (identifying the EPRI DER 

Settings Database as one potential technical source 

for IBR–DER estimation data). 

204Order 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). 

205See 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. 

206NERC’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. 

207CAISO Initial Comments at 38. 

208See Order No. 672, 114 FERC ¶ 61,104 at PP 

322, 325 (requiring that Reliability Standards be 

clear and unambiguous as to what is required and 

who is required to comply). 

209See NERC Rules of Procedure, App. 5B at 6. 

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 

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 

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 


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210NOPR, 181 FERC ¶ 61,125 at P 82. 

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 

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. 

215AEP 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. 

216AEP Initial Comments at 3–4. 

217CAISO Initial Comments at 29. 

218 Id. 

219 Id. at 26. 

220LADWP Reply Comments at 3. 

221NYSRC Initial Comments at 3. 

222 Id. 

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 

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 

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


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223NERC Initial Comments at 15–16. 

224 Id. 

225 Id. at 16. 

226 Id. 

227EPRI Initial Comments at 17. 

228ACP/SEIA Initial Comments at 12–13. 

229 ISO–NE Reply Comments at 3. 

230 Id. 

231See, 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. 

232See NERC Standardized Powerflow Parameters 

and Dynamics Models. 

233NOPR, 181 FERC ¶ 61,125 at P 36. 

234See Order No. 2023, 184 FERC ¶ 61,054 at P 

1660. 

235See 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 

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 

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, 

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 


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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.’’). 

236See 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’’). 

237See NYISO, Reliability Analysis Data Manual, 

22 (Dec. 2022), https://www.nyiso.com/documents/ 

20142/2924811/M-24-RAD-Att%20B-v2022-12-07- 

Final.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). 

238See Order No. 2023, 184 FERC ¶ 61,054 at P 

1659. 

239See NERC Initial Comments at 14 (describing 

multiple EMT modeling projects including a 

taskforce, Reliability Standards Project 2022–04 

(EMT Modeling), and a reliability guideline). 

240NOPR, 181 FERC ¶ 61,125 at P 84. 

241Although 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. 

242NERC 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. 

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 

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, 

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


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244EPRI Initial Comments at 8. 

245 Id. at 19–20 (referring to IEEE, Test and 

Verification of BPS-connected Inverter-Based 

Resources, P2800–2, https://sagroups.ieee.org/2800- 

2/). 

246 IRC Initial Comments at 3. 

247 Id. at 4. 

248CAISO Initial Comments at 30. 

249EPRI Initial Comments at 22. 

250ACP/SEIA Initial Comments at 12. 

251LADWP Reply Comments at 3. 

252NERC Initial Comments at 12; AEU Initial 

Comments at 6. 

253AEU Initial Comments at 6. 

254ACP/SEIA Initial Comments at 13. 

255 ISO–NE Initial Comments at 3; IRC Initial 

Comments at 4. 

256 ISO–NE Initial Comments at 4. 

257EPRI Initial Comments at 12–13. 

258NERC Initial Comments at 32; APS Initial 

Comments at 5; Indicated Trade Association Reply 

Comments at 2. 

259NERC Initial Comments at 32. 

260 Id. 

261APS Initial Comments at 5. 

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 

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 

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 


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262 Id. 

263SPP Initial Comments at 3. 

264We 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. 

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 

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 

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 


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74274 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

265We 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. 

266NOPR, 181 FERC ¶ 61,125 at P 79 n.157, P 80 

n.159. 

267 Id. 

268See NERC Standardized Powerflow Parameters 

and Dynamics Models. 

269See 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). 

270The 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. 

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). 

272See generally Aggregate DER Model 

Verification Guideline. 

273See generally 2023 DER_A Model Guideline. 

274See 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.). 

275See Massachusetts Technical Standards 

Review Group, Common Technical Standards 

Manual, 16 n.9 (Dec. 22, 2022), https://

www.mass.gov/doc/tsrg-common-guideline-2022- 

12-22/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)). 

276See 2023 DER_A Model Guideline at 18–19. 

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 

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 

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. 


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277Order No. 2023, 184 FERC ¶ 61,054 at P 1666. 

278 Id. 

279NOPR, 181 FERC ¶ 61,125 at P 40. 

280 Id. P 85. 

281NERC Initial Comments at 10; NYSRC Initial 

Comments at 1; CAISO Initial Comments at 30; AEP 

Initial Comments at 3. 

282NERC 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). 

283ACP/SEIA Initial Comments at 14. 

284 Id. at 10. 

285NERC Initial Comments at 11. 

286CAISO Initial Comments at 33. 

287APS Initial Comments at 5. 

288CAISO Initial Comments at 35–36. 

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 

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 

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 


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74276 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

289See generally IBR–DER Data Collection 

Guideline; Aggregate DER Model Verification 

Guideline. 

290See generally IBR–DER Data Collection 

Guideline. 

291See generally Aggregate DER Model 

Verification Guideline. 

292NOPR, 181 FERC ¶ 61,125 at PP 84–85. 

293NERC Initial Comments at 14; CAISO Initial 

Comments at 33; AEP Initial Comments at 1. 

294NERC Initial Comments at 14. 

295 Id. at 14–15. 

296CAISO Initial Comments at 31–32. 

297NOPR, 181 FERC ¶ 61,125 at P 85. 

298See Reliability Standard MOD–032–1 at 15 

(explaining that ‘‘presently, the Eastern/Quebec and 

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 

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 

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 


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Texas Interconnections build seasonal cases on an 

annual basis, while the Western Interconnection 

builds cases on a continuous basis throughout the 

year’’). 

299NOPR, 181 FERC ¶ 61,125 at P 87. 

300 Id. P 88. 

301See NERC Glossary at 23 (defining planning 

assessment as a ‘‘Documented evaluation of future 

Transmission System performance and Corrective 

Action Plans to remedy identified deficiencies.’’). 

302NOPR, 181 FERC ¶ 61,125 at P 88. 

303 Id. (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. 

304NERC 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. 

305NERC 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. 

306NOPR, 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.). 

coordinate, validate, and keep up-todate the transmission planning, 

operations, and interconnection-wide 

models. 

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 

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 

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 


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309 Id. P 89. 

310See, 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. 

311NERC Initial Comments at 19. 

312 Id. at 18. 

313 Id. at 18–19. 

314 Indicated Trade Associations Initial 

Comments at 7. 

315LADWP Reply Comments at 4. 

316 Id. at 4. 

317 IRC Initial Comments at 5. 

318SPP Initial Comments at 5. 

319NERC 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. 

320NERC Initial Comments at 20. 

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

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

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 

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 


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321NOPR, 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). 322See, 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 . . . ’’). 

323NOPR, 181 FERC ¶ 61,125 at P 52. 

324See, 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’’). 

325NOPR, 181 FERC ¶ 61,125 at P 90. 

326 Id. PP 93–95. 

327 Id. P 94. 

328 Id. P 90. 

329NERC, 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. 

330NERC 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. 

333AEU Initial Comments at 2. 

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 

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 

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 


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334CAISO Initial Comments at 11. 

335 Id. 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’’). 

336See, e.g., NERC Initial Comments at 22. 

337ACP/SEIA Initial Comments at 7–8; SPP Initial 

Comments at 6; Indicated Trade Associations Initial 

Comments at 8. 

338SCE/PG&E Initial Comments at 5. 

339ACP/SEIA Initial Comments at 1–2. 

340 Id. at 10–11. 

341 Id. at 7. 

342EPRI Initial Comments at 25. 

343 Id. at 5. 

344NERC Initial Comments at 22. 

345 Id. 

346AEU Initial Comments at 3. 

347 Indicated Trade Associations Initial 

Comments at 8. 

348 ISO–NE Initial Comments at 5. 

349UNIFI Initial Comments at 1. 

350ACP/SEIA 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). 

351CAISO Initial Comments at 17 (quoting 2021 

Solar PV Disturbances Report at 14). 

352NYSRC Initial Comments at 4. 

353 Id.; ISO–NE Initial Comments at 6. 

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 

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 


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354See infra P 209. 355Blue Cut Fire Event Report at 11–13. 356Odessa 2021 Disturbance Report at vii, 12–13. 357 2021 Solar PV Disturbances Report at vii, 15, 

31. 358March 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.’’). 

359Order No. 2023, 184 FERC ¶ 61,054 at P 1715. 

360See, e.g., NERC Initial Comments at 22; 

Indicated Trades Associations Initial Comments at 

8. 

361See generally 2021 Solar PV Disturbances 

Report at 14 (discussing momentary cessation from 

legacy facilities that cannot eliminate its use). 

362Reliability 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.’’). 

363See 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). 

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 

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. 

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 


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364See, 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). 

365See 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.’’). 

366See, e.g., 2021 Solar PV Disturbances Report 

at 14 (discussing technical limitations of legacy 

IBRs related to voltage control and momentary 

cessation). 

367NOPR, 181 FERC ¶ 61,125 at PP 94–95. 

368NYSRC Initial Comments at 4. 

369 Id. 

370 Indicated Trade Associations Initial 

Comments at 8. 

371See supra section IV.E.1. 

372NOPR, 181 FERC ¶ 61,125 at P 91. 

373 Id. 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’’). 

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. 

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

a. Comments 

197. NYSRC raises concerns with the 

Commission’s proposal because 

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. 

b. Commission Determination 

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 

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 


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376NOPR, 181 FERC ¶ 61,125 at P 96. 

377 Id. P 97. 

378 Id. 

379NERC Initial Comments at 5; AEP Initial 

Comments at 5; CAISO Initial Comments at 1; IRC 

Initial Comments at 5; NYSRC Initial Comments at 

1. 

380NERC Initial Comments at 22. 

381ACP/SEIA Initial Comments at 8. 

382 Id. 

383SPP Initial Comments at 4. 

384EPRI Initial Comments at 25. 

385NOPR, 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., 

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.’’). 

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

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 

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 


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387 Id. P 72. 

388 Id. P 73. 

389NERC Initial Comments at 23. 

390 Id. 

391 Id. at 23–24. 

392 Indicated Trade Associations Initial 

Comments at 2. 

393 Id. at 5. 

394 Id. at 6; IRC Initial Comments at 3. 

395SCE/PG&E Initial Comments at 9–11. 

396 Id. at 10. 

397NERC Initial Comments at 26–30. 

398 Id. at 24. 

399AEP Initial Comments at 5; CAISO Initial 

Comments at 5. 

400AEP Initial Comments at 6. 

401Bonneville Initial Comments at 1. 

402 Id. at 3. 

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 

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 

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 


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403Ohio FEA Initial Comments at 7. 

404ACP/SEIA Initial Comments at 4. 

405 18 CFR 39.2(d). 

406See, 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). 

407See IBR Registration Order, 181 FERC 

¶ 61,124. 

408NOPR, 181 FERC ¶ 61,125 at P 74. 

409NERC Initial Comments at 21–22. 

410See 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.’’). 

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 

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

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, 


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74286 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

411 44 U.S.C. 3507(d). 

412 5 CFR 1320.11. 

413Reliability 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. 

414Reguls. 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). 

415 18 CFR 380.4(a)(2)(ii). 

416 5 U.S.C. 601–612. 

417See, 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). 

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. 

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. 

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 

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 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 


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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 74287 

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. 

Issued October 19, 2023 

Kimberly D. Bose, 

Secretary. 

Appendix A: Commenter Names 

Acronyms Commenter name 

AEU ................................................. Advanced Energy United. 

ACP/SEIA ........................................ American Clean Power Association and Solar Energy Industries Association. 

AEP ................................................. American Electric Power Service Corporation. 

APS ................................................. Arizona Public Service Company. 

Bonneville ........................................ Bonneville Power Administration. 

CAISO ............................................. California Independent System Operator Corporation. 

EPRI ................................................ Electric Power Research Institute. 

Indicated Trade Associations .......... Edison Electric Institute, American Public Power Association, Large Public Power Council, National Rural 

Electric Cooperative Association, and Transmission Access Policy Study Group. 

infiniRel ........................................... infiniRel Corporation. 

ISO–NE ........................................... ISO New England Inc. 

IRC .................................................. ISO/RTO Council. 

NYSRC ............................................ New York State Reliability Council. 

LADWP ........................................... Los Angeles Department of Water and Power. 

Ohio FEA ........................................ Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate. 

Mr. Plankey ..................................... Sean P. Plankey. 

SCE/PG&E ...................................... Southern California Edison Company and Pacific Gas and Electric Company. 

SPP ................................................. Southwest Power Pool, Inc. 

UNIFI ............................................... 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 

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/ 

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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74288 Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 

1Reliability Standards to Address Inverter-Based 

Resources, 185 FERC ¶ 61,042 (2023). 

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. 

5NERC, 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. 

7Reliability Standards to Address Inverter-Based 

Resources, 185 FERC ¶ 61,042 at P 14 (citations 

omitted). 

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_

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-2023-03- 

14-01%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 

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 


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Federal Register / Vol. 88, No. 208 / Monday, October 30, 2023 / Rules and Regulations 74289 

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. 

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 

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 

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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